F O R M 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2005
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 1-11234
KINDER MORGAN ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0380342
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
500 Dallas Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-369-9000
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X] No [ ]
The Registrant had 148,562,814 common units outstanding as of April 30,
2005.
1
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
PART I. FINANCIAL INFORMATION
Item 1: Financial Statements (Unaudited)..................................... 3
Consolidated Statements of Income - Three Months Ended
March 31, 2005 and 2004............................................ 3
Consolidated Balance Sheets - March 31, 2005 and
December 31, 2004.................................................. 4
Consolidated Statements of Cash Flows - Three Months
Ended March 31, 2005 and 2004...................................... 5
Notes to Consolidated Financial Statements.......................... 6
Item 2: Management's Discussion and Analysis of Financial
Condition and Results of Operations................................ 49
Critical Accounting Policies and Estimates.......................... 49
Results of Operations............................................... 49
Financial Condition................................................. 58
Information Regarding Forward-Looking Statements.................... 62
Item 3: Quantitative and Qualitative Disclosures About Market Risk.......... 64
Item 4: Controls and Procedures............................................. 64
PART II. OTHER INFORMATION
Item 1: Legal Proceedings................................................... 65
Item 2: Unregistered Sales of Equity Securities and Use of Proceeds......... 65
Item 3: Defaults Upon Senior Securities..................................... 65
Item 4: Submission of Matters to a Vote of Security Holders................. 65
Item 5: Other Information................................................... 65
Item 6: Exhibits............................................................ 65
Signatures.......................................................... 67
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Unit Amounts)
(Unaudited)
Three Months Ended March 31,
2005 2004
---------- ----------
Revenues
Natural gas sales................................. $1,352,615 $1,326,294
Services.......................................... 443,425 372,120
Product sales and other........................... 175,892 123,842
---------- ----------
1,971,932 1,822,256
---------- ----------
Costs and Expenses
Gas purchases and other costs of sales............ 1,337,770 1,317,309
Operations and maintenance........................ 138,540 111,192
Fuel and power.................................... 41,940 33,508
Depreciation, depletion and amortization.......... 85,027 67,531
General and administrative........................ 73,852 48,254
Taxes, other than income taxes.................... 25,826 19,320
---------- ----------
1,702,955 1,597,114
---------- ----------
Operating Income.................................... 268,977 225,142
Other Income (Expense)
Earnings from equity investments.................. 26,072 20,469
Amortization of excess cost of equity investments. (1,417) (1,394)
Interest, net..................................... (58,727) (47,221)
Other, net........................................ (1,321) 743
Minority Interest................................... (2,388) (2,081)
---------- ----------
Income Before Income Taxes.......................... 231,196 195,658
Income Taxes........................................ (7,575) (3,904)
---------- ----------
Net Income.......................................... $ 223,621 $ 191,754
========== ==========
General Partner's interest in Net Income............ $ 111,727 $ 91,664
Limited Partners' interest in Net Income............ 111,894 100,090
---------- ----------
Net Income.......................................... $ 223,621 $ 191,754
=========== ==========
Basic and Diluted Limited Partners' Net Income per
Unit................................................ $ 0.54 $ 0.52
=========== ==========
Weighted average number of units used in computation
of Limited Partners' Net Income per unit:
Basic............................................... 207,528 192,512
=========== ==========
Diluted............................................. 207,584 192,602
=========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
3
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
March 31, December 31,
----------- -----------
ASSETS 2005 2004
----------- -----------
Current Assets
Cash and cash equivalents................................ $ - $ -
Restricted deposits...................................... 18,096 -
Accounts, notes and interest receivable, net
Trade................................................. 667,555 739,798
Related parties....................................... 18,083 12,482
Inventories
Products.............................................. 19,778 17,868
Materials and supplies................................ 12,314 11,345
Gas imbalances
Trade................................................. 29,238 24,653
Related parties....................................... 1,358 980
Gas in underground storage............................... 5,318 -
Other current assets..................................... 95,290 46,045
----------- -----------
867,030 853,171
----------- -----------
Property, Plant and Equipment, net......................... 8,195,625 8,168,680
Investments................................................ 423,937 413,255
Notes receivable
Trade.................................................... 1,944 1,944
Related parties.......................................... 111,225 111,225
Goodwill................................................... 745,926 732,838
Other intangibles, net..................................... 39,310 15,284
Deferred charges and other assets.......................... 260,820 256,545
----------- -----------
Total Assets............................................... $10,645,817 $10,552,942
=========== ===========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts.................................. $ 21,307 $ 29,866
Trade................................................. 584,119 685,034
Related parties....................................... 3,052 16,650
Current portion of long-term debt........................ - -
Accrued interest......................................... 36,889 56,930
Accrued taxes............................................ 42,072 26,435
Deferred revenues........................................ 15,931 7,825
Gas imbalances........................................... 37,124 32,452
Accrued other current liabilities........................ 577,874 325,663
----------- -----------
1,318,368 1,180,855
----------- -----------
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding........................................... 4,867,521 4,722,410
Market value of interest rate swaps................... 77,156 130,153
----------- -----------
4,944,677 4,852,563
Deferred revenues........................................ 12,649 14,680
Deferred income taxes.................................... 56,742 56,487
Asset retirement obligations............................. 37,513 37,464
Other long-term liabilities and deferred credits......... 830,595 468,727
----------- -----------
5,882,176 5,429,921
Commitments and Contingencies (Note 3)
Minority Interest.......................................... 40,619 45,646
----------- -----------
Partners' Capital
Common Units............................................. 2,409,790 2,438,011
Class B Units............................................ 116,349 117,414
i-Units.................................................. 1,724,391 1,694,971
General Partner.......................................... 107,609 103,467
Accumulated other comprehensive loss..................... (953,485) (457,343)
----------- -----------
3,404,654 3,896,520
Total Liabilities and Partners' Capital.................... $10,645,817 $10,552,942
=========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
4
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Increase/(Decrease) in Cash and Cash Equivalents In Thousands)
(Unaudited)
Three Months Ended March 31,
----------------------------
2005 2004
---------- ----------
Cash Flows From Operating Activities
Net income.................................................... $ 223,621 $ 191,754
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization.................... 85,027 67,531
Amortization of excess cost of equity investments........... 1,417 1,394
Earnings from equity investments............................ (26,072) (20,469)
Distributions from equity investments......................... 13,386 19,187
Changes in components of working capital:
Accounts receivable......................................... 49,284 16,671
Other current assets........................................ (10,239) 27,845
Inventories................................................. (2,245) 461
Accounts payable............................................ (95,343) 1,481
Accrued liabilities......................................... (12,429) (40,830)
Accrued taxes............................................... 15,636 10,222
Other, net.................................................... 17,464 (5,137)
---------- ----------
Net Cash Provided by Operating Activities....................... 259,507 270,110
---------- ----------
Cash Flows From Investing Activities
Acquisitions of assets........................................ (6,476) (50,281)
Additions to property, plant and equip. for
expansion and maintenance projects............................ (143,808) (149,718)
Sale of investments, property, plant and
equipment, net of removal costs............................... 2,900 3,076
Investments in margin deposits................................ (18,096) --
Contributions to equity investments........................... (18) (445)
Natural gas stored underground and natural
gas liquids line-fill......................................... (1,905) 1,608
Other......................................................... (588) (851)
---------- ----------
Net Cash Used in Investing Activities........................... (167,991) (196,611)
---------- ----------
Cash Flows From Financing Activities
Issuance of debt.............................................. 1,327,433 1,289,378
Payment of debt............................................... (1,182,630) (1,408,260)
Debt issue costs.............................................. (4,477) (244)
Decrease in cash book overdrafts.............................. (8,560) --
Proceeds from issuance of common units........................ 1,167 238,051
Proceeds from issuance of i-units............................. -- 14,925
Contributions from General Partner............................ 409 2,919
Distributions to partners:
Common units................................................ (109,191) (91,620)
Class B units............................................... (3,932) (3,613)
General Partner............................................. (107,585) (87,128)
Minority interest........................................... (2,761) (2,301)
Other, net.................................................... (1,389) (2,074)
---------- ----------
Net Cash Used in Financing Activities........................... (91,516) (49,967)
---------- ----------
Increase in Cash and Cash Equivalents........................... -- 23,532
Cash and Cash Equivalents, beginning of period.................. -- 23,329
---------- ----------
Cash and Cash Equivalents, end of period........................ $ -- $ 46,861
========== ==========
Noncash Investing and Financing Activities:
Assets acquired by the assumption of liabilities.............. 284 2,812
The accompanying notes are an integral part of these
consolidated financial statements.
5
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Organization
General
Unless the context requires otherwise, references to "we," "us," "our" or
the "Partnership" are intended to mean Kinder Morgan Energy Partners, L.P. and
its consolidated subsidiaries. We have prepared the accompanying unaudited
consolidated financial statements under the rules and regulations of the
Securities and Exchange Commission. Under such rules and regulations, we have
condensed or omitted certain information and notes normally included in
financial statements prepared in conformity with accounting principles generally
accepted in the United States of America. We believe, however, that our
disclosures are adequate to make the information presented not misleading. The
consolidated financial statements reflect all adjustments which are solely
normal and recurring adjustments that are, in the opinion of our management,
necessary for a fair presentation of our financial results for the interim
periods. You should read these consolidated financial statements in conjunction
with our consolidated financial statements and related notes included in our
Annual Report on Form 10-K for the year ended December 31, 2004.
Kinder Morgan, Inc. and Kinder Morgan Management, LLC
Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of
Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware
corporation, is the sole stockholder of our general partner, Kinder Morgan G.P.,
Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report.
Kinder Morgan Management, LLC, a Delaware limited liability company, was
formed on February 14, 2001. Our general partner owns all of Kinder Morgan
Management, LLC's voting securities and, pursuant to a delegation of control
agreement, our general partner delegated to Kinder Morgan Management, LLC, to
the fullest extent permitted under Delaware law and our partnership agreement,
all of its power and authority to manage and control our business and affairs,
except that Kinder Morgan Management, LLC cannot take certain specified actions
without the approval of our general partner. Under the delegation of control
agreement, Kinder Morgan Management, LLC manages and controls our business and
affairs and the business and affairs of our operating limited partnerships and
their subsidiaries. Furthermore, in accordance with its limited liability
company agreement, Kinder Morgan Management, LLC's activities are limited to
being a limited partner in, and managing and controlling the business and
affairs of us, our operating limited partnerships and their subsidiaries. Kinder
Morgan Management, LLC is referred to as "KMR" in this report.
Basis of Presentation
Our consolidated financial statements include our accounts and those of our
majority-owned and controlled subsidiaries and our operating partnerships. All
significant intercompany items have been eliminated in consolidation. Certain
amounts from prior periods have been reclassified to conform to the current
presentation.
Net Income Per Unit
We compute Basic Limited Partners' Net Income per Unit by dividing our
limited partners' interest in net income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the potential dilution, by application of the treasury stock method,
that could occur if options to issue units were exercised, which would result in
the issuance of additional units that would then share in our net income.
6
2. Acquisitions and Joint Ventures
During the first three months of 2005, we completed or made adjustments for
the following acquisitions. Each of the acquisitions was accounted for under the
purchase method and the assets acquired and liabilities assumed were recorded at
their estimated fair market values as of the acquisition date. The preliminary
allocation of assets and liabilities may be adjusted to reflect the final
determined amounts during a short period of time following the acquisition. The
results of operations from these acquisitions are included in our consolidated
financial statements from the acquisition date.
Allocation of Purchase Price
-------------------------------------------------------------------
(in millions)
-------------------------------------------------------------------
Property Deferred
Purchase Current Plant & Charges Minority
Ref. Date Acquisition Price Assets Equipment & Other Goodwill Interest
----- -------------------------------------------------- ---------- -------- --------- --------- -------- ---------
(1) 1/02 Kinder Morgan Materials Services LLC...... $ 14.4 $0.9 $13.5 $ - $ - $ -
(2) 8/04 Kinder Morgan Wink Pipeline, L.P.......... 100.3 0.1 76.4 23.8 - -
(3) 11/04 Charter Products Terminals................ 75.2 3.7 56.5 3.0 13.1 (1.1)
(4) 1/05 Claytonville Oil Field Unit .............. $ 6.5 $ - $ 6.5 $ - $ - $ -
(1) Kinder Morgan Materials Services LLC
Effective January 1, 2002, we acquired all of the equity interests of
Kinder Morgan Materials Services LLC, formerly Laser Materials Services LLC, for
an aggregate consideration of $14.4 million, consisting of approximately $11.1
million in cash and the assumption of approximately $3.3 million of liabilities,
including long-term debt of $0.4 million. In the first quarter of 2005, we paid
$0.3 million to the previous owners for final earn-out provisions pursuant to
the purchase and sale agreement. Kinder Morgan Materials Services LLC currently
operates approximately 60 transload facilities in 20 states. The facilities
handle dry-bulk products, including aggregates, plastics and liquid chemicals.
The acquisition of Kinder Morgan Materials Services LLC expanded our growing
terminal operations and is part of our Terminals business segment.
(2) Kinder Morgan Wink Pipeline, L.P.
Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P. from KPL Pipeline Company, LLC and RHC Holdings,
L.P. for a purchase price of approximately $100.3 million, consisting of $89.9
million in cash and the assumption of approximately $10.4 million of
liabilities, including debt of $9.5 million. In September 2004, we paid the $9.5
million outstanding debt balance. We renamed the limited partnership Kinder
Morgan Wink Pipeline, L.P., and since August 31, 2004, we have included its
results as part of our CO2 business segment. The acquisition included a 450-mile
crude oil pipeline system, consisting of four mainline sections, numerous
gathering systems and truck off-loading stations. The mainline sections, all in
Texas, have a total capacity of 115,000 barrels of crude oil per day. As part of
the transaction, we entered into a long-term throughput agreement with Western
Refining Company, L.P. to transport crude oil into Western's 107,000 barrel per
day refinery in El Paso, Texas. As of April 30, 2005, we expected to invest
approximately $13.7 million over the next two years to upgrade the assets. The
acquisition allows us to better manage crude oil deliveries from our oil field
interests in West Texas. Our allocation of the purchase price to assets acquired
and liabilities assumed was based on an independent appraisal of fair market
values. The $23.8 million of deferred charges and other assets in the table
above represents the fair value of the intangible long-term throughput
agreement.
(3) Charter Products Terminals
Effective November 5, 2004, we acquired ownership interests in nine refined
petroleum products terminals in the southeastern United States from Charter
Terminal Company and Charter-Triad Terminals, LLC for approximately $75.2
million, consisting of $72.4 million in cash and $2.8 million of assumed
liabilities. Three terminals are located in Selma, North Carolina, and the
remaining facilities are located in Greensboro and Charlotte, North Carolina;
Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta, South
Carolina. We fully own seven of the terminals and jointly own the remaining two.
The nine facilities have a combined 3.2 million barrels of storage. As of our
acquisition date, we expected to invest an additional $2 million over the next
two years to upgrade the facilities. All of the terminals are connected to
products pipelines owned by either Plantation Pipe Line Company or Colonial
Pipeline Company. The acquisition complements the existing terminals we own in
the Southeast and increased our southeast terminal storage
7
capacity 76% (to 7.7 million barrels) and terminal throughput capacity 62% (to
over 340,000 barrels per day). The acquired terminals are included as part of
our Products Pipelines business segment. Our allocation of the purchase price to
assets acquired and liabilities assumed is preliminary, pending final purchase
price adjustments that may be necessary following an independent appraisal of
fair market values. We expect the appraisal to be completed by the end of the
second quarter of 2005.
(4) Claytonville Oil Field Unit
Effective January 31, 2005, we acquired an approximate 64.5% gross working
interest in the Claytonville oil field unit located in Fisher County, Texas from
Aethon I L.P. The field is located nearly 30 miles east of the SACROC unit in
the Permian Basin of West Texas. Our purchase price was approximately $6.5
million, consisting of $6.2 million in cash and the assumption of $0.3 million
of liabilities. Following our acquisition, we became the operator of the field,
which at the time of acquisition was producing approximately 200 barrels of oil
per day. The acquisition of this ownership interest complemented our existing
carbon dioxide assets in the Permian Basin, and as of our acquisition date and
pending further studies as to the technical and economic feasibility of carbon
dioxide injection, we may invest an additional $30 million in the field in order
to increase production to as high as 4,000 barrels of oil per day. The acquired
operations are included as part of our CO2 business segment.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement
information for the three months ended March 31, 2005 and 2004, assumes that all
of the acquisitions we have made and joint ventures we have entered into since
January 1, 2004, including the ones listed above, had occurred as of the
beginning of the period presented. We have prepared these unaudited pro forma
financial results for comparative purposes only. These unaudited pro forma
financial results may not be indicative of the results that would have occurred
if we had completed these acquisitions and joint ventures as of the beginning of
the period presented or the results that will be attained in the future. Amounts
presented below are in thousands, except for the per unit amounts:
Pro Forma
Three Months Ended March 31,
----------------------------
2005 2004
---------- ----------
(Unaudited)
Revenues................................. $1,972,169 $1,861,651
Operating Income......................... 269,094 238,227
Net Income............................... $ 223,724 $ 203,882
Basic and Diluted Limited Partners'
Net Income per unit:............... $ 0.54 $ 0.57
3. Litigation and Other Contingencies
SFPP, L.P.
Federal Energy Regulatory Commission Proceedings
SFPP, L.P., referred to in this report as SFPP, is the subsidiary limited
partnership that owns our Pacific operations, excluding CALNEV Pipe Line LLC and
related terminals acquired from GATX Corporation. Tariffs charged by SFPP are
subject to certain proceedings at the FERC involving shippers' complaints
regarding the interstate rates, as well as practices and the jurisdictional
nature of certain facilities and services, on our Pacific operations' pipeline
systems.
OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a
consolidated proceeding that began in September 1992 and includes a number of
shipper complaints against certain rates and practices on SFPP's East Line (from
El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California
to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson
Station in Carson, California. The complainants in the case are El Paso
Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company,
Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products
Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing
Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.),
Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco
Corporation (now part of ConocoPhillips Company). The FERC
8
has ruled that the complainants have the burden of proof in this proceeding.
A FERC administrative law judge held hearings in 1996, and issued an initial
decision in September 1997. The initial decision held that all but one of SFPP's
West Line rates were "grandfathered" under the Energy Policy Act of 1992 and
therefore deemed to be just and reasonable; it further held that complainants
had failed to prove "substantially changed circumstances" with respect to those
rates and that they therefore could not be challenged in the Docket No. OR92-8
et al. proceedings, either for the past or prospectively. However, the initial
decision also made rulings generally adverse to SFPP on certain cost of service
issues relating to the evaluation of East Line rates, which are not
"grandfathered" under the Energy Policy Act. Those issues included the capital
structure to be used in computing SFPP's "starting rate base," the level of
income tax allowance SFPP may include in rates and the recovery of civil and
regulatory litigation expenses and certain pipeline reconditioning costs
incurred by SFPP. The initial decision also held SFPP's Watson Station gathering
enhancement service was subject to FERC jurisdiction and ordered SFPP to file a
tariff for that service.
The FERC subsequently reviewed the initial decision, and issued a series of
orders in which it adopted certain rulings made by the administrative law judge,
changed others and modified a number of its own rulings on rehearing. Those
orders began in January 1999, with FERC Opinion No. 435, and continued through
June 2003.
The FERC affirmed that all but one of SFPP's West Line rates are
"grandfathered" and that complainants had failed to satisfy the threshold burden
of demonstrating "substantially changed circumstances" necessary to challenge
those rates. The FERC further held that the one West Line rate that was not
grandfathered did not need to be reduced. The FERC consequently dismissed all
complaints against the West Line rates in Docket Nos. OR92-8 et al. without any
requirement that SFPP reduce, or pay any reparations for, any West Line rate.
The FERC initially modified the initial decision's ruling regarding the
capital structure to be used in computing SFPP's "starting rate base" to be more
favorable to SFPP, but later reversed that ruling. The FERC also made certain
modifications to the calculation of the income tax allowance and other cost of
service components, generally to SFPP's disadvantage.
On multiple occasions, the FERC required SFPP to file revised East Line rates
based on rulings made in the FERC's various orders. SFPP was also directed to
submit compliance filings showing the calculation of the revised rates, the
potential reparations for each complainant and in some cases potential refunds
to shippers. SFPP filed such revised East Line rates and compliance filings in
March 1999, July 2000, November 2001 (revised December 2001), October 2002 and
February 2003 (revised March 2003). Most of those filings were protested by
particular SFPP shippers. The FERC has held that certain of the rates SFPP filed
at the FERC's directive should be reduced retroactively and/or be subject to
refund; SFPP has challenged the FERC's authority to impose such requirements in
this context.
While the FERC initially permitted SFPP to recover certain of its litigation,
pipeline reconditioning and environmental costs, either through a surcharge on
prospective rates or as an offset to potential reparations, it ultimately
limited recovery in such a way that SFPP was not able to make any such surcharge
or take any such offset. Similarly, the FERC initially ruled that SFPP would not
owe reparations to any complainant for any period prior to the date on which
that party's complaint was filed, but ultimately held that each complainant
could recover reparations for a period extending two years prior to the filing
of its complaint (except for Navajo, which was limited to one month of
pre-complaint reparations under a settlement agreement with SFPP's predecessor).
The FERC also ultimately held that SFPP was not required to pay reparations or
refunds for Watson Station gathering enhancement fees charged prior to filing a
FERC tariff for that service.
In April 2003, SFPP paid complainants and other shippers reparations and/or
refunds as required by FERC's orders. In August 2003, SFPP paid shippers an
additional refund as required by FERC's most recent order in the Docket No.
OR92-8 et al. proceedings. We made aggregate payments of $44.9 million in 2003
for reparations and refunds pursuant to a FERC order.
Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond
Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for
review of FERC's Docket OR92-8 et al. orders in the United States Court of
Appeals for the District of Columbia Circuit. Certain of those petitions were
dismissed by the Court of Appeals as premature, and the remaining petitions were
held in abeyance pending completion of agency action. However, in
9
December 2002, the Court of Appeals returned to its active docket all petitions
to review the FERC's orders in the case through November 2001 and severed
petitions regarding later FERC orders. The severed orders were held in abeyance
for later consideration.
Briefing in the Court of Appeals was completed in August 2003, and oral
argument took place on November 12, 2003. On July 20, 2004, the U.S. Court of
Appeals for the District of Columbia Circuit issued an opinion affirming the
FERC orders under review on most issues, vacating the tax provision that the
FERC had allowed SFPP to include under the FERC's "Lakehead" policy giving a tax
allowance to partnership pipelines and remanding for further FERC proceedings on
other issues.
The court held that, in the context of the Docket No. OR92-8, et al.
proceedings, all of SFPP's West Line rates were grandfathered other than the
charge for use of SFPP's Watson Station gathering enhancement facility and the
rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded
that the FERC had a reasonable basis for concluding that the addition of a West
Line origin point at East Hynes, California did not involve a new "rate" for
purposes of the Energy Policy Act. It rejected arguments from West Line Shippers
that certain protests and complaints had challenged West Line rates prior to the
enactment of the Energy Policy Act.
The court also held that complainants had failed to satisfy their burden of
demonstrating substantially changed circumstances, and therefore could not
challenge grandfathered West Line rates in the Docket No. OR92-8 et al.
proceedings. It specifically rejected arguments that other shippers could
"piggyback" on the special Energy Policy Act exception permitting Navajo to
challenge grandfathered West Line rates, which Navajo had withdrawn under a
settlement with SFPP. The court remanded the changed circumstances issue "for
further consideration" by the FERC in light of the court's decision, described
below, regarding SFPP's tax allowance. The FERC had previously held in the
OR96-2 proceeding that the tax allowance policy should not be used as a
stand-alone factor in determining when there have been substantially changed
circumstances. The FERC's May 4, 2005 income tax allowance policy statement,
discussed below, may affect how the FERC addresses the changed circumstances and
other issues remanded by the court.
The court upheld the FERC's rulings on most East Line rate issues. However, it
found the FERC's reasoning inadequate on some issues, including the tax
allowance.
The court held the FERC had sufficient evidence to use SFPP's December 1988
stand-alone capital structure to calculate its starting rate base as of June
1985. It rejected SFPP arguments that would have resulted in a higher starting
rate base.
The court analyzed at length the tax allowance for pipelines that are
organized as partnerships. It concluded that the FERC had provided "no rational
basis" on the record before it for giving SFPP a tax allowance, and denied
recovery by SFPP of "income taxes not incurred and not paid."
The court accepted the FERC's treatment of regulatory litigation costs,
including the limitation of recoverable costs and their offset against
"unclaimed reparations" - that is, reparations that could have been awarded to
parties that did not seek them. The court also accepted the FERC's denial of any
recovery for the costs of civil litigation by East Line shippers against SFPP
based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix.
However, the court did not find adequate support for the FERC's decision to
allocate the limited litigation costs that SFPP was allowed to recover in its
rates equally between the East Line and the West Line, and ordered the FERC to
explain that decision further on remand.
The court held the FERC had failed to justify its decision to deny SFPP any
recovery of funds spent to recondition pipe on the East Line, for which SFPP had
spent nearly $6 million between 1995 and 1998. It concluded that the
Commission's reasoning was inconsistent and incomplete, and remanded for further
explanation, noting that "SFPP's shippers are presently enjoying the benefits of
what appears to be an expensive pipeline reconditioning program without sharing
in any of its costs."
The court affirmed the FERC's rulings on reparations in all respects. It held
the Arizona Grocery doctrine did not apply to orders requiring SFPP to file
"interim" rates, and that "FERC only established a final rate at the completion
of the OR92-8 proceedings." It held that the Energy Policy Act did not limit
complainants' ability to seek reparations for up to two years prior to the
filing of complaints against rates that are not grandfathered. It rejected
SFPP's arguments that the FERC should not have used a "test period" to compute
reparations, that it should have offset years in which there
10
were underrecoveries against those in which there were overrecoveries, and that
it should have exercised its discretion against awarding any reparations in this
case.
The court also rejected:
- Navajo's argument that its prior settlement with SFPP's predecessor
did not limit its right to seek reparations;
- Valero's argument that it should have been permitted to recover
reparations in the Docket No. OR92-8 et al. proceedings rather than
waiting to seek them, as appropriate, in the Docket No. OR96-2 et al.
proceedings;
- arguments that the former ARCO and Texaco had challenged East Line
rates when they filed a complaint in January 1994 and should therefore
be entitled to recover East Line reparations; and
- Chevron's argument that its reparations period should begin two years
before its September 1992 protest regarding the six-inch line reversal
rather than its August 1993 complaint against East Line rates.
On September 2, 2004, BP West Coast Products, ChevronTexaco, ConocoPhillips
and ExxonMobil filed a petition for rehearing and rehearing en banc asking the
Court of Appeals to reconsider its ruling that West Line rates were not subject
to investigation at the time the Energy Policy Act was enacted. On September 3,
2004, SFPP filed a petition for rehearing asking the Court to confirm that the
FERC has the same discretion to address the income tax allowance issue on remand
that administrative agencies normally have when their decisions are set aside by
reviewing courts because they have failed to provide a reasoned basis for their
conclusions. On October 4, 2004, the Court of Appeals denied both petitions
without further comment.
On November 2, 2004, the Court of Appeals issued its mandate remanding the
proceedings to the FERC. SFPP and shipper parties subsequently filed various
pleadings with the FERC regarding the proper nature and scope of the remand
proceedings. The FERC has not yet issued an order regarding the Docket No.
OR92-8 remand proceedings, but on December 2, 2004, it issued a Notice of
Inquiry and opened a new proceeding (Docket No. PL05-5) to consider how broadly
the court's ruling on the tax allowance issue should affect the range of
entities the FERC regulates. A number of parties filed comments in response to
that notice on January 21, 2005.
On December 17, 2004, the Court of Appeals issued orders directing that the
petitions for review relating to FERC orders issued after November 2001, which
had previously been severed from the main Court of Appeals docket, should
continue to be held in abeyance pending completion of the remand proceedings
before the FERC.
On January 3, 2005, SFPP filed a petition for a writ of certiorari asking
the United States Supreme Court to review the Court of Appeals' ruling that the
Arizona Grocery doctrine does not apply to "interim" rates, and that "FERC only
established a final rate at the completion of the OR92-8 proceedings." BP West
Coast Products and ExxonMobil also filed a petition for certiorari, on December
30, 2004, seeking review of the Court of Appeals' ruling that there was no
pending investigation of West Line rates at the time of enactment of the Energy
Policy Act (and thus that those rates remained grandfathered). On April 6, 2005,
the Solicitor General filed a brief in opposition to both petitions on behalf of
the FERC and United States, and Navajo, ConocoPhillips, Ultramar, Valero and
Western Refining filed an opposition to SFPP's petition. SFPP filed a reply to
those briefs on April 18, 2005.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC
(Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines (Line
Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject
to FERC's jurisdiction under the Interstate Commerce Act, and claimed that the
rate for that service was unlawful. Several other West Line shippers filed
similar complaints and/or motions to intervene.
Following a hearing in March 1997, a FERC administrative law judge issued
an initial decision holding that the movements on the Sepulveda pipelines were
not subject to FERC jurisdiction. On August 5, 1997, the FERC reversed that
decision. On October 6, 1997, SFPP filed a tariff establishing the initial
interstate rate for movements on the Sepulveda pipelines at the pre-existing
rate of five cents per barrel. Several shippers protested that rate. In December
1997, SFPP filed an application for authority to charge a market-based rate for
the Sepulveda service, which application was protested by several parties. On
September 30, 1998, the FERC issued an order finding that SFPP lacks market
power in the Watson Station destination market and set a hearing to determine
whether SFPP possessed market power in the origin market.
11
Following a hearing, on December 21, 2000, an administrative law judge found
that SFPP possessed market power over the Sepulveda origin market. On February
28, 2003, the FERC issued an order upholding that decision. SFPP filed a request
for rehearing of that order on March 31, 2003. The FERC denied SFPP's request
for rehearing on July 9, 2003.
As part of its February 28, 2003 order denying SFPP's application for
market-based ratemaking authority, the FERC remanded to the ongoing litigation
in Docket No. OR96-2, et al. the question of whether SFPP's current rate for
service on the Sepulveda line is just and reasonable. A hearing in this
proceeding was held in February and March 2005. The matter is now being briefed
to the administrative law judge in this proceeding.
OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar Diamond
Shamrock Corporation filed a complaint at FERC (Docket No. OR97-2) challenging
SFPP's West Line rates, claiming they were unjust and unreasonable and no longer
subject to grandfathering. In October 1997, ARCO, Mobil and Texaco filed a
complaint at the FERC (Docket No. OR98-1) challenging the justness and
reasonableness of all of SFPP's interstate rates, raising claims against SFPP's
East and West Line rates similar to those that have been at issue in Docket Nos.
OR92-8, et al. discussed above, but expanding them to include challenges to
SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno,
Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line. In
November 1997, Ultramar filed a similar, expanded complaint (Docket No. OR98-2).
Tosco Corporation filed a similar complaint in April 1998. The shippers seek
both reparations and prospective rate reductions for movements on all of SFPP's
lines. The FERC accepted the complaints and consolidated them into one
proceeding (Docket No. OR96-2, et al.), but held them in abeyance pending a FERC
decision on review of the initial decision in Docket Nos. OR92-8, et al.
In a companion order to Opinion No. 435, the FERC gave the complainants an
opportunity to amend their complaints in light of Opinion No. 435, which the
complainants did in January 2000. In August 2000, Navajo and Western filed
complaints against SFPP's East Line rates and Ultramar filed an additional
complaint updating its pre-existing challenges to SFPP's interstate pipeline
rates. These complaints were consolidated with the ongoing proceeding in Docket
No. OR96-2, et al.
A hearing in this consolidated proceeding was held from October 2001 to March
2002. A FERC administrative law judge issued his initial decision on June 24,
2003. The initial decision found that, for the years at issue, the complainants
had shown substantially changed circumstances for rates on SFPP's West, North
and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson
Station and thus found that those rates should not be "grandfathered" under the
Energy Policy Act of 1992. The initial decision also found that most of SFPP's
rates at issue were unjust and unreasonable.
On March 26, 2004, the FERC issued an order on the phase one initial decision.
The FERC's phase one order reversed the initial decision by finding that SFPP's
rates for its North and Oregon Lines should remain "grandfathered" and amended
the initial decision by finding that SFPP's West Line rates (i) to Yuma, Tucson
and CalNev, as of 1995, and (ii) to Phoenix, as of 1997, should no longer be
"grandfathered" and are not just and reasonable. The FERC's phase one order did
not address prospective West Line rates and whether reparations are necessary.
As discussed below, those issues have been addressed in the non-binding phase
two initial decision recently issued by the presiding administrative law judge.
The FERC's phase one order also did not address the "grandfathered" status of
the Watson Station fee, noting that it would address that issue once it was
ruled on by the United States Court of Appeals for the District of Columbia
Circuit in its review of the FERC's Opinion No. 435 orders. Several of the
participants in the proceeding requested rehearing of the FERC's phase one
order. FERC action on those requests is pending. In addition, several
participants, including SFPP, filed petitions with the United States Court of
Appeals for the District of Columbia Circuit for review of the FERC's phase one
order. On August 13, 2004, the FERC filed a motion to dismiss the pending
petitions for review of the phase one order, which Petitioners, including SFPP,
answered on August 30, 2004. On December 20, 2004, the Court referred the FERC's
motion to the merits panel and directed the parties to address the issues in
that motion on brief, thus effectively dismissing the FERC's motion. In the same
order, the Court granted a motion to hold the petitions for review of the FERC's
phase one order in abeyance and directed the parties to file motions to govern
future proceeding 30 days after FERC disposition of the pending rehearing
requests.
12
The FERC's phase one order also held that SFPP failed to seek authorization
for the accounting entries necessary to reflect in SFPP's books, and thus in its
annual report to FERC ("FERC Form 6"), the purchase price adjustment ("PPA")
arising from SFPP's 1998 acquisition by us. The phase one order directed SFPP to
file for permission to reflect the PPA in its FERC Form 6 for the calendar year
1998 and each subsequent year. In its April 26, 2004 compliance filing, SFPP
noted that it had previously requested such permission and that the FERC's
regulations require an oil pipeline to include a PPA in its Form 6 without first
seeking FERC permission to do so. Several parties protested SFPP's compliance
filing. SFPP answered those protests, and FERC action on this matter is pending.
On September 9, 2004, the presiding administrative law judge issued his
non-binding initial decision in the phase two portion of this proceeding. If
affirmed by the FERC, the phase two initial decision would establish the basis
for prospective rates and the calculation of reparations for complaining
shippers with respect to the West Line and East Line. However, as with the phase
one initial decision, the phase two initial decision must be fully reviewed by
the FERC, which may accept, reject or modify the decision. A FERC order on phase
two of the case is expected during the second or third quarter of 2005. Any such
order may be subject to further FERC review, review by the United States Court
of Appeals for the District of Columbia Circuit, or both.
We are not able to predict with certainty the final outcome of the pending
FERC proceedings involving SFPP, should they be carried through to their
conclusion, or whether we can reach a settlement with some or all of the
complainants. The final outcome will depend, in part, on the outcomes of the
appeals of these proceedings and the OR92-8, et al. proceedings taken by SFPP,
complaining shippers, and an intervenor.
We estimated, as of December 31, 2003, that shippers' claims for reparations
totaled approximately $154 million and that prospective rate reductions would
have an aggregate average annual impact of approximately $45 million. As the
timing for implementation of rate reductions and the payment of reparations is
extended, total estimated reparations and the interest accruing on the
reparations increase. For each calendar quarter of delay in the implementation
of rate reductions sought, we estimate that reparations and accrued interest
accumulates by approximately $9 million. We now assume that any potential rate
reductions will be implemented no earlier than the third quarter of 2005 and
that reparations and accrued interest thereon will be paid no earlier than the
third quarter of 2006; however, the timing, and nature, of any rate reductions
and reparations that may be ordered will likely be affected by the FERC's income
tax allowance inquiry in Docket No. PL05-5 and the FERC's disposition of issues
remanded by the D.C. Circuit in the BP West Coast decision. If the phase two
initial decision were to be largely adopted by the FERC, the estimated
reparations and rate reductions would be larger than noted above; however, we
continue to estimate the combined annual impact of the rate reductions and the
capital costs associated with financing the payment of reparations sought by
shippers and accrued interest thereon to be approximately 15 cents of
distributable cash flow per unit. We believe, however, that the ultimate
resolution of these complaints will be for amounts substantially less than the
amounts sought.
Chevron complaint OR02-4 proceedings. On February 11, 2002, Chevron, an
intervenor in the Docket No. OR96-2, et al. proceeding, filed a complaint
against SFPP in Docket No. OR02-4 along with a motion to consolidate the
complaint with the Docket No. OR96-2, et al. proceeding. On May 21, 2002, the
FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed a
request for rehearing, which the FERC dismissed on September 25, 2002. In
October 2002, Chevron filed a request for rehearing of the FERC's September 25,
2002 Order, which the FERC denied on May 23, 2003. On July 1, 2003, Chevron
filed a petition for review of this denial at the U.S. Court of Appeals for the
District of Columbia Circuit. On August 18, 2003, SFPP filed a motion to dismiss
Chevron's petition on the basis that Chevron lacks standing to bring its appeal
and that the case is not ripe for review. Chevron answered on September 10,
2003. SFPP's motion was pending, when the Court of Appeals, on December 8, 2003,
granted Chevron's motion to hold the case in abeyance pending the outcome of the
appeal of the Docket No. OR92-8, et al. proceeding. On January 8, 2004, the
Court of Appeals granted Chevron's motion to have its appeal of the FERC's
decision in Docket No. OR03-5 (see below) consolidated with Chevron's appeal of
the FERC's decision in the Docket No. OR02-4 proceeding. On December 10, 2004,
the Court dismissed Chevron's petition for review in Docket No. OR03-5 and set
Chevron's appeal of the FERC's orders in OR02-4 for briefing. On January 4,
2005, the Court granted Chevron's request to hold such briefing in abeyance
until after final disposition of the OR96-2 proceeding. Chevron continues to
participate in the Docket No. OR96-2 et al. proceeding as an intervenor.
13
Chevron OR03-5 proceedings. On June 30, 2003, Chevron filed another complaint
against SFPP - substantially similar to its previous complaint - and moved to
consolidate the complaint with the Docket No. OR96-2, et al. proceeding. This
complaint was docketed as Docket No. OR03-5. Chevron requested that this new
complaint be treated as if it were an amendment to its complaint in Docket No.
OR02-4, which was previously dismissed by the FERC. By this request, Chevron
sought to, in effect, back-date its complaint, and claim for reparations, to
February 2002. SFPP answered Chevron's complaint on July 22, 2003, opposing
Chevron's requests for consolidation and for the back-dating of its complaint.
On October 28, 2003, the FERC accepted Chevron's complaint, but held it in
abeyance pending the outcome of the Docket No. OR96-2, et al. proceeding. The
FERC denied Chevron's request for consolidation and for back-dating.
On November 21, 2003, Chevron filed a petition for review of the FERC's
October 28, 2003 Order at the Court of Appeals for the District of Columbia
Circuit. On January 8, 2004, the Court of Appeals granted Chevron's motion to
have its appeal consolidated with Chevron's appeal of the FERC's decision in the
Docket No. OR02-4 proceeding and to have the two appeals held in abeyance
pending the outcome of the appeal of the Docket No. OR92-8, et al. proceeding.
On August 13, 2004, the FERC filed a motion to dismiss the pending petitions for
review of the FERC's orders in the OR02-4 and OR03-5 proceedings. SFPP filed a
motion to dismiss Chevron's petitions for review on August 18, 2004. On December
10, 2004, the Court granted the motions to dismiss.
Airlines OR04-3 proceeding. On September 21, 2004, America West Airlines,
Inc., Southwest Airlines, Co., Northwest Airlines, Inc. and Continental
Airlines, Inc. (collectively "Airlines") filed a complaint against SFPP at the
FERC. The Airlines' complaint alleges that the rates on SFPP's West Line and
SFPP's charge for its gathering enhancement service at Watson Station are not
just and reasonable. The Airlines seek rate reductions and reparations for two
years prior to the filing of their complaint. BP West Coast Products LLC and
ExxonMobil Oil Corporation, ConocoPhillips Company, Navajo Refining Company,
L.P., and ChevronTexaco Products Company all filed timely motions to intervene
in this proceeding. Valero Marketing and Supply Company filed a motion to
intervene one day after the deadline. SFPP answered the Airlines' complaint on
October 12, 2004. On October 29, 2004, the Airlines filed a response to SFPP's
answer and on November 12, 2004, SFPP replied to the Airlines' response. On
March 24, 2005, the Airlines filed a motion seeking expedited action by the FERC
on their complaint. FERC action on the motion and the complaint is pending.
BP/ExxonMobil OR05-4 proceeding. On December 22, 2004, BP West Coast Products
LLC and ExxonMobil Oil Corporation filed a complaint against SFPP at the FERC.
The complaint alleges that SFPP's interstate rates are not just and reasonable,
that certain rates found grandfathered by the FERC are not entitled to such
status, and, if so entitled, that "substantially changed circumstances" have
occurred, removing such protection. The complainants seek rate reductions and
reparations for two years prior to the filing of their complaint and ask that
the complaint be consolidated with the Airlines' complaint in the OR04-3
proceeding. ConocoPhillips Company, Navajo Refining Company, L.P., and Western
Refining Company, L.P. all filed timely motions to intervene in this proceeding.
SFPP answered the complaint on January 24, 2005. On February 25, 2005, the FERC
consolidated this docket with the OR05-5 proceeding and held both in abeyance
until after the conclusion of the various pending SFPP proceedings, deferring
any ruling on the validity of the complaints.
ConocoPhillips OR05-5 proceeding. On December 29, 2004, ConocoPhillips filed a
complaint against SFPP at the FERC. The complaint alleges that SFPP's interstate
rates are not just and reasonable, that certain rates found grandfathered by the
FERC are not entitled to such status, and, if so entitled, that "substantially
changed circumstances" have occurred, removing such protection. ConocoPhillips
seeks rate reductions and reparations for two years prior to the filing of their
complaint. BP West Coast Products LLC and ExxonMobil Oil Corporation, Navajo
Refining Company, L.P., and Western Refining Company, L.P. all filed timely
motions to intervene in this proceeding. SFPP answered the complaint on January
28, 2005. On February 25, 2005, the FERC consolidated this docket with the
OR05-4 proceeding and held both in abeyance until after the conclusion of the
various pending SFPP proceedings, deferring any ruling on the validity of the
complaints.
California Public Utilities Commission Proceeding
ARCO, Mobil and Texaco filed a complaint against SFPP with the California
Public Utilities Commission on April 7, 1997. The complaint challenges rates
charged by SFPP for intrastate transportation of refined petroleum
14
products through its pipeline system in the State of California and requests
prospective rate adjustments. On October 1, 1997, the complainants filed
testimony seeking prospective rate reductions aggregating approximately $15
million per year.
On August 6, 1998, the CPUC issued its decision dismissing the complainants'
challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC granted limited
rehearing of its August 1998 decision for the purpose of addressing the proper
ratemaking treatment for partnership tax expenses, the calculation of
environmental costs and the public utility status of SFPP's Sepulveda Line and
its Watson Station gathering enhancement facilities. In pursuing these rehearing
issues, complainants sought prospective rate reductions aggregating
approximately $10 million per year.
On March 16, 2000, SFPP filed an application with the CPUC seeking authority
to justify its rates for intrastate transportation of refined petroleum products
on competitive, market-based conditions rather than on traditional,
cost-of-service analysis.
On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC
asserting that SFPP's California intrastate rates are not just and reasonable
based on a 1998 test year and requesting the CPUC to reduce SFPP's rates
prospectively. The amount of the reduction in SFPP rates sought by the
complainants is not discernible from the complaint.
The rehearing complaint was heard by the CPUC in October 2000 and the April
2000 complaint and SFPP's market-based application were heard by the CPUC in
February 2001. All three matters stand submitted as of April 13, 2001, and
resolution of these submitted matters may occur within the second or third
quarter of 2005.
The CPUC subsequently issued a resolution approving a 2001 request by SFPP to
raise its California rates to reflect increased power costs. The resolution
approving the requested rate increase also required SFPP to submit cost data for
2001, 2002, and 2003, and to assist the CPUC in determining whether SFPP's
overall rates for California intrastate transportation services are reasonable.
The resolution reserves the right to require refunds, from the date of issuance
of the resolution, to the extent the CPUC's analysis of cost data to be
submitted by SFPP demonstrates that SFPP's California jurisdictional rates are
unreasonable in any fashion. On February 21, 2003, SFPP submitted the cost data
required by the CPUC, which submittal was protested by Valero Marketing and
Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil
Corporation and Chevron Products Company. Issues raised by the protest,
including the reasonableness of SFPP's existing intrastate transportation rates,
were the subject of evidentiary hearings conducted in December 2003 and may be
resolved by the CPUC in the second or third quarter of 2005.
On November 22, 2004, SFPP filed an application with the CPUC requesting a $9
million increase in existing intrastate rates to reflect the in-service date of
SFPP's replacement and expansion of its Concord-to-Sacramento pipeline. The
requested rate increase, which automatically became effective as of December 22,
2004 pursuant to California Public Utilities Code Section 455.3, is being
collected subject to refund, pending resolution of protests to the application
by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products
LLC, Exxon Mobil Oil Corporation and ChevronTexaco Products Company. The CPUC is
expected to resolve the matter by the fourth quarter of 2005.
We currently believe the CPUC complaints seek approximately $15 million in
tariff reparations and prospective annual tariff reductions, the aggregate
average annual impact of which would be approximately $31 million. There is no
way to quantify the potential extent to which the CPUC could determine that
SFPP's existing California rates are unreasonable. With regard to the amount of
dollars potentially subject to refund as a consequence of the CPUC resolution
requiring the provision by SFPP of cost-of-service data, referred to above, such
refunds could total about $6 million per year from October 2002 to the
anticipated date of a CPUC decision.
SFPP believes the submission of the required, representative cost data
required by the CPUC indicates that SFPP's existing rates for California
intrastate services remain reasonable and that no refunds are justified.
We believe that the resolution of such matters will not have a material
adverse effect on our business, financial position, results of operations or
cash flows.
15
Union Pacific Railroad Company Easements
SFPP, L.P. and Union Pacific Railroad Company (the successor to Southern
Pacific Transportation Company) are engaged in two proceedings to determine the
extent, if any, to which the rent payable by SFPP for the use of pipeline
easements on rights-of-way held by UPRR should be adjusted pursuant to existing
contractual arrangements for each of the ten year periods beginning January 1,
1994 and January 1, 2004 (Southern Pacific Transportation Company vs. Santa Fe
Pacific Corporation, SFP Properties, Inc., Santa Fe Pacific Pipelines, Inc.,
SFPP, L.P., et al., Superior Court of the State of California for the County of
San Francisco, filed August 31, 1994; and Union Pacific Railroad Company vs.
Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. "D",
Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for
the County of Los Angeles, filed July 28, 2004). In the second quarter of 2003,
the trial court set the rent for years 1994 - 2003 at approximately $5.0 million
per year as of January 1, 1994, subject to annual inflation increases throughout
the ten year period. On February 23, 2005, the California Court of Appeals
affirmed the trial court's ruling, except that it reversed a small portion of
the decision and remanded it back to the trial court for determination. We do
not expect this portion of the decision to have a material impact on the rent.
On August 17, 2004, SFPP was served with a lawsuit seeking to determine the
rent for the ten year period commencing January 1, 2004. A trial date has not
been set.
ARB, Inc. Dispute
ARB, Inc, a general contractor engaged by SFPP, L.P. to build a 20-inch
70-mile pipeline from Concord to Sacramento, California is seeking additional
payments based on alleged scope changes and delays on the project. After
deducting for payments made by SFPP to date, ARB asserts that it is owed between
$13.1 million and $16.8 million on the project. ARB has indicated that its
calculation of outstanding amounts may be increased in the future pending
further analysis. SFPP has engaged construction claims specialists and auditors
to review the project records and determine what additional payments, if any,
should be made to ARB. Numerous third party subcontractors have filed liens
against ARB and SFPP. SFPP has requested that ARB honor its contractual
obligation to avoid and discharge any liens arising on the project.
Standards of Conduct Rulemaking
FERC Order No. 2004
On November 25, 2003, the FERC issued Order No. 2004, adopting new
Standards of Conduct to become effective February 9, 2004. Every interstate
natural gas pipeline was required to file a compliance plan by that date and was
required to be in full compliance with the Standards of Conduct by June 1, 2004.
The primary change from existing regulation is to make such standards applicable
to an interstate natural gas pipeline's interaction with many more affiliates
(referred to as "energy affiliates"), including intrastate/Hinshaw natural gas
pipelines (in general, a Hinshaw pipeline is a pipeline that receives gas at or
within a state boundary, is regulated by an agency of that state, and all the
gas it transports is consumed within that state), processors and gatherers and
any company involved in natural gas or electric markets (including natural gas
marketers) even if they do not ship on the affiliated interstate natural gas
pipeline. Local distribution companies are excluded, however, if they do not
make sales to customers not physically attached to their system. The Standards
of Conduct require, among other things, separate staffing of interstate
pipelines and their energy affiliates (but support functions and senior
management at the central corporate level may be shared) and strict limitations
on communications from an interstate pipeline to an energy affiliate.
Kinder Morgan Interstate Gas Transmission LLC filed for clarification and
rehearing of Order No. 2004 on December 29, 2003. In the request for rehearing,
Kinder Morgan Interstate Gas Transmission LLC asked that intrastate/Hinshaw
pipeline affiliates not be included in the definition of energy affiliates. On
February 19, 2004, Kinder Morgan Interstate Gas Transmission LLC and Trailblazer
Pipeline Company filed exemption requests with the FERC. The pipelines seek a
limited exemption from the requirements of Order No. 2004 for the purpose of
allowing their affiliated Hinshaw and intrastate pipelines, which are subject to
state regulation and do not make any sales to customers not physically attached
to their system, to be excluded from the rule's definition of energy affiliate.
Separation from these entities would be the most burdensome requirement of the
new rules for us.
16
On April 16, 2004, the FERC issued Order No. 2004-A. The FERC extended the
effective date of the new Standards of Conduct from June 1, 2004, to September
1, 2004. Otherwise, the FERC largely denied rehearing of Order No. 2004, but
provided further clarification or adjustment in several areas. The FERC
continued the exemption for local distribution companies which do not make
off-system sales, but clarified that the local distribution company exemption
still applies if the local distribution company is also a Hinshaw pipeline. The
FERC also clarified that a local distribution company can engage in certain
sales and other energy affiliate activities to the limited extent necessary to
support sales to customers located on its distribution system, and sales
necessary to remain in balance under pipeline tariffs, without becoming an
energy affiliate. The FERC declined to exempt natural gas producers. The FERC
also declined to exempt natural gas intrastate and Hinshaw pipelines, processors
and gatherers, but did clarify that such entities will not be energy affiliates
if they do not participate in gas or electric commodity markets, interstate
capacity markets (as capacity holder, agent or manager), or in financial
transactions related to such markets.
The FERC also clarified further the personnel and functions which can be
shared by interstate natural gas pipelines and their energy affiliates,
including senior officers and risk management personnel, and the permissible
role of holding or parent companies and service companies. The FERC also
clarified that day-to-day operating information can be shared by interconnecting
entities. Finally, the FERC clarified that an interstate natural gas pipeline
and its energy affiliate can discuss potential new interconnects to serve the
energy affiliate, but subject to very onerous posting and record-keeping
requirements.
On July 21, 2004, Kinder Morgan Interstate Gas Transmission LLC and
Trailblazer Pipeline Company filed additional joint requests with the interstate
natural gas pipelines owned by KMI asking for limited exemptions from certain
requirements of FERC Order 2004 and asking for an extension of the deadline for
full compliance with Order 2004 until 90 days after the FERC has completed
action on the pipelines' various rehearing and exemption requests. These
exemptions request relief from the independent functioning and information
disclosure requirements of Order 2004. The exemption requests propose to treat
as energy affiliates, within the meaning of Order 2004, two groups of employees:
- individuals in the Choice Gas Commodity Group within KMI's retail
operations; and
- commodity sales and purchase personnel within our Texas intrastate
natural gas operations.
Order 2004 regulations governing relationships between interstate pipelines
and their energy affiliates would apply to relationships with these two groups.
Under these proposals, certain critical operating functions could continue to be
shared.
On August 2, 2004, the FERC issued Order No. 2004-B. In this order, the
FERC extended the effective date of the new Standards of Conduct from September
1, 2004 to September 22, 2004. Also in this order, among other actions, the FERC
denied the request for rehearing made by the interstate pipelines of KMI and us
to clarify the applicability of the local distribution company and parent
company exemptions to them. In addition, the FERC denied the interstate
pipelines' request for a 90 day extension of time to comply with Order 2004.
On September 20, 2004, the FERC issued an order which conditionally granted
the July 21, 2004 joint requests for limited exemptions from the requirements of
the Standards of Conduct described above. In that order, FERC directed Kinder
Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company and the
affiliated interstate pipelines owned by KMI to submit compliance plans
regarding these exemptions within 30 days. These compliance plans were filed on
October 19, 2004, and set out certain steps taken by us to assure that employees
in the Choice Gas Commodity Group of KMI and the commodity sales and purchase
personnel of our Texas intrastate organizations do not have access to restricted
interstate natural gas pipeline information or receive preferential treatment as
to interstate natural gas pipeline services. The FERC will not enforce
compliance with the independent functioning requirement of the Standards of
Conduct as to these employees until 30 days after it acts on these compliance
filings. In all other respects, we were required to comply with the Standards of
Conduct as of September 22, 2004.
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We have implemented compliance with the Standards of Conduct as of
September 22, 2004, subject to the exemptions described in the prior paragraph.
Compliance includes, among other things, the posting of compliance procedures
and organizational information for each interstate pipeline on its Internet
website, the posting of discount and tariff discretion information and the
implementation of independent functioning for energy affiliates not covered by
the prior paragraph (electric and gas gathering, processing or production
affiliates).
On December 21, 2004, the FERC issued Order No. 2004-C. In this order, the
FERC granted rehearing on certain issues and also clarified certain provisions
in the previous FERC 2004 orders. The primary impact on us from Order 2004-C is
the granting of rehearing and allowing local distribution companies to
participate in hedging activity related to on-system sales and still qualify for
exemption from being an energy affiliate.
By an order issued on April 19, 2005, the FERC accepted the compliance
plans filed by us without modification, but subject to further amplification and
clarification as to the intrastate group in three areas:
- further description and explanation of the information or events
relating to intrastate pipeline business that the shared transmission
function personnel may discuss with our commodity sales and purchase
personnel within our Texas intrastate natural gas operations;
- additional posting of organizational information about the commodity
sales and purchase personnel within our Texas intrastate natural gas
operations; and
- clarification that the president of our intrastate natural gas
pipeline group has received proper training and will not be a conduit
for improperly sharing transmission or customer information with our
commodity sales and purchase personnel within our Texas intrastate
natural gas operations.
FERC Policy statement re: Use of Gas Basis Differentials for Pricing
On July 25, 2003, the FERC issued a Modification to Policy Statement
stating that FERC regulated natural gas pipelines will, on a prospective basis,
no longer be permitted to use gas basis differentials to price negotiated rate
transactions. Effectively, we will no longer be permitted to use commodity price
indices to structure transactions on our FERC regulated natural gas pipelines.
Negotiated rates based on commodity price indices in existing contracts will be
permitted to remain in effect until the end of the contract period for which
such rates were negotiated. Moreover, in subsequent orders in individual
pipeline cases, the FERC has allowed negotiated rate transactions using pricing
indices so long as revenue is capped by the applicable maximum rate(s).
Rehearing on this aspect of the Modification to Policy Statement has been sought
by several pipelines, but the FERC has not yet acted on rehearing. Price indexed
contracts currently constitute an insignificant portion of our contracts on our
FERC regulated natural gas pipelines; consequently, we do not believe that this
Modification to Policy Statement will have a material impact on our operations,
financial results or cash flows.
Accounting for Integrity Testing Costs
On November 5, 2004, the FERC issued a Notice of Proposed Accounting
Release that would require FERC jurisdictional entities to recognize costs
incurred in performing pipeline assessments that are a part of a pipeline
integrity management program as maintenance expense in the period incurred. The
proposed accounting ruling was in response to the FERC's finding of diverse
practices within the pipeline industry in accounting for pipeline assessment
activities. The proposed ruling would standardize these practices. Specifically,
the proposed ruling clarifies the distinction between costs for a "one-time
rehabilitation project to extend the useful life of the system," which could be
capitalized, and costs for an "on-going inspection and testing or maintenance
program," which would be accounted for as maintenance and charged to expense in
the period incurred. Comments, along with responses to specific questions posed
by FERC concerning the Notice of Proposed Accounting Release, were due January
19, 2005. We filed our comments on January 19, 2005, asking the FERC to modify
the accounting release to allow capitalization of pipeline assessment costs
associated with projects involving 100 feet or more of pipeline being replaced
or recoated (including discontinuous sections) and to adopt an effective date
for the final rule which is no earlier than January 1, 2006.
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Selective Discounting
On November 22, 2004, the FERC issued a notice of inquiry seeking comments on
its policy of selective discounting. Specifically, the FERC is asking parties to
submit comments and respond to inquiries regarding the FERC's practice of
permitting pipelines to adjust their ratemaking throughput downward in rate
cases to reflect discounts given by pipelines for competitive reasons - when the
discount is given to meet competition from another gas pipeline. Comments were
filed by numerous entities, including Natural Gas Pipeline Company of America (a
Kinder Morgan, Inc. affiliate), on March 2, 2005. Several reply comments have
subsequently been filed.
On February 20, 2004, the D.C. Circuit Court of Appeals for the District of
Columbia remanded back to the FERC a Williston Basin Interstate Pipeline
proceeding in which the court ruled that the FERC did not explain how the
selective discounting policy adopted by the FERC in the Colorado Interstate Gas
Co. and Granite State Gas Transmission cases would not compromise the pipelines'
ability to target discounts at particular receipt/delivery points, subsystems or
other defined geographic areas. On June 1, 2004, the FERC issued a Notice of
Request for Comments in the Williston Basin Interstate Pipeline proceeding, on
issues pertaining to the discounting policy adopted in the Colorado Interstate
Gas Co. and Granite State Gas Transmission cases. Comments were due on August 9,
2004. Numerous parties filed comments, including our three interstate natural
gas pipelines: Kinder Morgan Interstate Gas Transmission LLC, Trailblazer
Pipeline Company and TransColorado Gas Transmission Company. On March 3, 2005,
the FERC issued an Order on Remand in the Williston Basin Interstate Pipeline,
Co. proceeding (RP00-463). The FERC has concluded that it cannot, at the present
time, satisfy its burden under Section 5 of the Natural Gas Act to require
Williston or other pipelines to modify their tariffs to incorporate the
CIG/Granite State policy. The FERC will return to its pre-existing policy of
permitting pipelines to limit the selective discounts they offer shippers to
particular points. Pipelines who implemented the CIG/Granite State policy
pursuant to orders that are now final may file pursuant to Section 4 of the
Natural Gas Act to remove their tariff provisions implementing that policy. Our
interstate natural gas pipelines have filed to remove these tariff provisions.
Other Regulatory
SFPP, L.P.
As discussed above, under "SFPP, L.P. - Federal Regulatory Commission
Proceedings," on July 20, 2004, the United States Court of Appeals for the
District of Columbia Circuit issued its opinion in BP West Coast Products, LLC
v. Federal Energy Regulatory Commission, No. 99-1020, On Petitions for Review of
Orders of the Federal Energy Regulatory Commission (Circuit opinion), addressing
in part the tariffs of SFPP, L.P. Among other things, the Circuit Court opinion
vacated the income tax allowance portion of the FERC opinion and order allowing
recovery in SFPP's rates for income taxes and remanded this and other matters
for further proceedings consistent with the Circuit Court opinion. By its terms,
the opinion only pertains to SFPP, L.P. and it is based on the record in that
case.
However, on December 2, 2004, the FERC issued a Notice of Inquiry seeking
comments on the implications of the July 20, 2004 opinion of the Court of
Appeals for the District of Columbia Circuit in BP West Coast Producers, LLC, v.
FERC. In reviewing a series of orders involving SFPP, L.P., the court held,
among other things, that the FERC had not adequately justified its policy of
providing an oil pipeline limited partnership with an income tax allowance equal
to the proportion of its limited partnership interests owned by corporate
partners. The FERC is seeking comments on whether the court's ruling applies
only to the specific facts of the SFPP, L.P. proceeding, or also extends to
other capital structures involving partnerships and other forms of ownership.
Comments were filed by numerous parties, including our Rocky Mountain natural
gas pipelines, in the first quarter of 2005.
On May 4, 2005, the FERC adopted a policy statement in Docket No. PL05-5,
providing that all entities owning public utility assets - oil and gas pipelines
and electric utilities - would be permitted to include an income tax allowance
in their cost-of-service rates to reflect the actual or potential income tax
liability attributable to their public utility income, regardless of the form of
ownership. Any tax pass-through entity seeking an income tax allowance would
have to establish that its partners or members have an actual or potential
income tax obligation on the entity's public utility income. The FERC expressed
the intent to implement its policy in individual cases as they arise. Subject to
that case-specific implementation, the policy appears to provide an opportunity
for partnership-
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owned pipelines to seek allowances based upon their entire income paid to
partners, rather than the partial allowance provided under the prior Lakehead
approach. We expect the final adoption and implementation by the FERC of the
policy statement in individual cases will be subject to review of the United
States Court of Appeals for the District of Columbia Circuit. Evaluation of the
impact of this policy statement will have to await further developments in
SFPP's pending cases.
Trailblazer Pipeline Company
On March 22, 2005, Marathon Oil Company filed a formal complaint with FERC
alleging that Trailblazer Pipeline Company violated the FERC's Negotiated Rate
Policy Statement and the Natural Gas Act by failing to offer a recourse rate
option for its Expansion 2002 capacity and by charging negotiated rates higher
than the applicable recourse rates. Marathon is requesting that the FERC require
Trailblazer to refund all amounts paid by Marathon above Trailblazer's Expansion
2002 recourse rate since the facilities went into service in May 2002, with
interest. In addition, Marathon is asking the FERC to require Trailblazer to
bill Marathon the Expansion 2002 recourse rate for future billings. Marathon
estimates the amount of Trailblazer's refund to date is over $15 million.
Trailblazer filed its response to Marathon's complaint in April 2005 and the
matter is currently before the FERC for review.
Other
In addition to the matters described above, we may face additional
challenges to our rates in the future. Shippers on our pipelines do have rights
to challenge the rates we charge under certain circumstances prescribed by
applicable regulations. There can be no assurance that we will not face
challenges to the rates we receive for services on our pipeline systems in the
future. In addition, since many of our assets are subject to regulation, we are
subject to potential future changes in applicable rules and regulations that may
have an adverse effect on our business, financial position, results of
operations or cash flows.
Carbon Dioxide Litigation
Kinder Morgan CO2 Company, L.P., Kinder Morgan G.P., Inc., and Cortez
Pipeline Company are among the named defendants in Shores, et al. v. Mobil Oil
Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas
filed December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil
Corp., et al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed
March 29, 2001). These cases were originally filed as class actions on behalf of
classes of overriding royalty interest owners (Shores) and royalty interest
owners (Bank of Denton) for damages relating to alleged underpayment of
royalties on carbon dioxide produced from the McElmo Dome Unit. Although classes
were initially certified at the trial court level, appeals resulted in the
decertification and/or abandonment of the class claims. On February 22, 2005,
the trial judge dismissed both cases for lack of jurisdiction. Counsel for some
of the individual plaintiffs in these cases has indicated that those plaintiffs
may refile their claims.
On May 13, 2004, William Armor, one of the former plaintiffs in the Shores
matter whose claims were dismissed for improper venue by the Court of Appeals,
filed a new case alleging the same claims (in summary, seeking damages for
underpayment of royalties based on alleged breaches of contractual duties and
covenants, agency duties, civil conspiracy, and related claims) against the same
defendants previously sued in the Shores case, including Kinder Morgan CO2
Company, L.P. and Kinder Morgan Energy Partners, L.P. Armor v. Shell Oil
Company, et al, No. 04-03559 (14th Judicial District, Dallas County Court filed
May 13, 2004). Defendants filed their answers and special exceptions on June 4,
2004. Trial, if necessary, has been scheduled for July 25, 2005.
Shell CO2 Company, Ltd., predecessor in interest to Kinder Morgan CO2
Company, L.P., is among the named counter-claim defendants in Shell Western E&P
Inc. v. Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial
District Court, Harris County, Texas filed June 17, 1998) (the "SWEPI Action").
The counter-claim plaintiffs are overriding royalty interest owners in the
McElmo Dome Unit and have sued seeking damages for underpayment of royalties on
carbon dioxide produced from the McElmo Dome Unit. The counter-claim plaintiffs
have asserted claims for fraud/fraudulent inducement, real estate fraud,
negligent misrepresentation, breach of fiduciary duty, breach of contract,
negligence, negligence per se, unjust enrichment, violation of the Texas
Securities Act, and open account. Counter-claim plaintiffs seek actual damages,
punitive damages, an accounting, and
20
declaratory relief. The trial court granted a series of summary judgment motions
filed by counter-claim defendants on all of counter-plaintiffs' counter-claims
except for the fraud-based claims. In 2004, one of the counter-plaintiffs
(Gerald Bailey) amended his counter-suit to allege purported claims as a private
relator under the False Claims Act and antitrust claims. The federal government
elected to not intervene in the False Claims Act counter-suit. On March 24,
2005, Bailey filed a notice of removal, and the case was transferred to federal
court. Shell Western E&P Inc. v. Gerald O. Bailey and Bridwell Oil Company, No.
H-05-1029 (S.D. Tex., Houston Division removed March 24, 2005). Also on March
24, 2005, Bailey filed an instrument under seal in the federal court that, based
on recent filings in the federal court discussing the sealed instrument, appears
to be a motion to transfer venue of the removed Bailey federal court action to
the federal district court of Colorado, in which Bailey has filed another suit
against Kinder Morgan CO2 Company, L.P. asserting claims under the False Claims
Act. The Houston federal district judge has ordered that Bailey take steps to
have the False Claims Act case pending in Colorado transferred to Houston, and
has also suggested that the claims of other plaintiffs in other carbon dioxide
litigation pending in Texas should be transferred to the Bailey federal court
action pending in Houston. Bailey has filed a brief requesting that the Bailey
federal court action pending in Houston be transferred to Colorado. Kinder
Morgan CO2 Company, L.P. intends to seek dismissal of all of the counter-claim
plaintiffs' claims through appropriate motions. No current trial date is set.
On March 1, 2004, Bridwell Oil Company, one of the named
defendants/counter-claim plaintiffs in the SWEPI Action, filed a new matter in
which it asserts claims which are virtually identical to the counter-claims it
asserts against Shell CO2 Company, Ltd. in the SWEPI Action. Bridwell Oil Co. v.
Shell Oil Co. et al, No. 160,199-B (78th Judicial District, Wichita County Court
filed March 1, 2004). The defendants in this action include Kinder Morgan CO2
Company, L.P., Kinder Morgan Energy Partners, L.P., various Shell entities,
ExxonMobil entities, and Cortez Pipeline Company. On June 25, 2004, defendants
filed answers, special exceptions, pleas in abatement, and motions to transfer
venue back to the Harris County District Court. On January 31, 2005, the Wichita
County judge abated the case pending resolution of the Bailey action.
Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company are among the
named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al.,
No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case
involves claims by overriding royalty interest owners in the McElmo Dome and Doe
Canyon Units seeking damages for underpayment of royalties on carbon dioxide
produced from the McElmo Dome Unit, failure to develop carbon dioxide reserves
at the Doe Canyon Unit, and failure to develop hydrocarbons at both McElmo Dome
and Doe Canyon. The plaintiffs also possess a small working interest at Doe
Canyon. Plaintiffs claim breaches of contractual and potential fiduciary duties
owed by the defendants and also allege other theories of liability including
breach of covenants, civil theft, conversion, fraud/fraudulent concealment,
violation of the Colorado Organized Crime Control Act, deceptive trade
practices, and violation of the Colorado Antitrust Act. In addition to actual or
compensatory damages, plaintiffs seek treble damages, punitive damages, and
declaratory relief relating to the Cortez Pipeline tariff and the method of
calculating and paying royalties on McElmo Dome carbon dioxide. Plaintiffs'
motion for summary judgment concerning alleged underpayment of McElmo Dome
overriding royalties is currently pending before the Court. The parties are
continuing to engage in discovery. No trial date is currently set.
J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD,
individually and on behalf of all other private royalty and overriding royalty
owners in the Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v.
Kinder Morgan CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court,
Union County New Mexico).
This case involves a purported class action against Kinder Morgan CO2
Company, L.P. alleging that defendant has failed to pay the full royalty and
overriding royalty ("royalty interests") on the true and proper settlement value
of compressed carbon dioxide produced from the Bravo Dome Unit in the period
beginning January 1, 2000. The complaint purports to assert claims for violation
of the New Mexico Unfair Practices Act, constructive fraud, breach of contract
and of the covenant of good faith and fair dealing, breach of the implied
covenant to market, and claims for an accounting, unjust enrichment, and
injunctive relief. The purported class is comprised of current and former
owners, during the period January 2000 to the present, who have private property
royalty interests burdening the oil and gas leases held by the defendant,
excluding the Commissioner of Public Lands, the United States of America, and
those private royalty interests that are not unitized as part of the Bravo Dome
Unit. The plaintiffs allege that they were members of a class previously
certified as a class action by the United States District Court for the District
21
of New Mexico in the matter Doris Feerer, et al. v. Amoco Production Company, et
al., USDC N.M. Civ. No. 95-0012 (the "Feerer Class Action"). Plaintiffs allege
that defendant's method of paying royalty interests is contrary to the
settlement of the Feerer Class Action. Defendant has filed a Motion to Compel
Arbitration of this matter pursuant to the arbitration provisions contained in
the Feerer Class Action Settlement Agreement, which motion was denied by the
trial court. An appeal of that ruling has been filed and is pending before the
New Mexico Court of Appeals. No date for arbitration or trial is currently set.
In addition to the matters listed above, various audits and administrative
inquiries concerning Kinder Morgan CO2 Company L.P.'s royalty and tax payments
on carbon dioxide produced from the McElmo Dome Unit are currently ongoing.
These audits and inquiries involve various federal agencies, the State of
Colorado, the Colorado oil and gas commission, and Colorado county taxing
authorities.
RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et
al. (Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District).
On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with
the First Supplemental Petition filed by RSM Production Corporation on behalf of
the County of Zapata, State of Texas and Zapata County Independent School
District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition
to 15 other defendants, including two other Kinder Morgan affiliates. Certain
entities we acquired in the Kinder Morgan Tejas acquisition are also defendants
in this matter. The Petition alleges that these taxing units relied on the
reported volume and analyzed heating content of natural gas produced from the
wells located within the appropriate taxing jurisdiction in order to properly
assess the value of mineral interests in place. The suit further alleges that
the defendants undermeasured the volume and heating content of that natural gas
produced from privately owned wells in Zapata County, Texas. The Petition
further alleges that the County and School District were deprived of ad valorem
tax revenues as a result of the alleged undermeasurement of the natural gas by
the defendants. On December 15, 2001, the defendants filed motions to transfer
venue on jurisdictional grounds. On June 12, 2003, plaintiff served discovery
requests on certain defendants. On July 11, 2003, defendants moved to stay any
responses to such discovery.
United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil
Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado).
This action was filed on June 9, 1997 pursuant to the federal False Claims
Act and involves allegations of mismeasurement of natural gas produced from
federal and Indian lands. The Department of Justice has decided not to intervene
in support of the action. The complaint is part of a larger series of similar
complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately
330 other defendants). Certain entities we acquired in the Kinder Morgan Tejas
acquisition are also defendants in this matter. An earlier single action making
substantially similar allegations against the pipeline industry was dismissed by
Judge Hogan of the U.S. District Court for the District of Columbia on grounds
of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed
individual complaints in various courts throughout the country. In 1999, these
cases were consolidated by the Judicial Panel for Multidistrict Litigation, and
transferred to the District of Wyoming. The multidistrict litigation matter is
called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions
to dismiss were filed and an oral argument on the motion to dismiss occurred on
March 17, 2000. On July 20, 2000, the United States of America filed a motion to
dismiss those claims by Grynberg that deal with the manner in which defendants
valued gas produced from federal leases, referred to as valuation claims. Judge
Downes denied the defendant's motion to dismiss on May 18, 2001. The United
States' motion to dismiss most of plaintiff's valuation claims has been granted
by the court. Grynberg has appealed that dismissal to the 10th Circuit, which
has requested briefing regarding its jurisdiction over that appeal.
Subsequently, Grynberg's appeal was dismissed for lack of appellate
jurisdiction. Discovery to determine issues related to the Court's subject
matter jurisdiction arising out of the False Claims Act is complete. Briefing
has been completed and oral arguments on jurisdiction were held before the
Special Master on March 17 and 18, 2005. On May 7, 2003, Grynberg sought leave
to file a Third Amended Complaint, which adds allegations of undermeasurement
related to carbon dioxide production. Defendants have filed briefs opposing
leave to amend. Neither the Court nor the Special Master has ruled on Grynberg's
Motion to Amend.
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Mel R. Sweatman and Paz Gas Corporation v. Gulf Energy Marketing, LLC, et
al.
On July 25, 2002, we were served with this suit for breach of contract,
tortious interference with existing contractual relationships, conspiracy to
commit tortious interference and interference with prospective business
relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection
with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to be
shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder Morgan
Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this action
eliminated profit on Kinder Morgan Tejas, a portion of which Mr. Sweatman and
Paz Gas Corporation claim they are entitled to receive under an agreement with a
subsidiary of ours acquired in the Tejas Gas acquisition. We filed a motion to
remove the case from venue in Dewitt County, Texas to Harris County, Texas, and
our motion was denied in a venue hearing in November 2002.
In a Second Amended Original Petition, Sweatman and Paz assert new and
distinct allegations against us, principally that we were a party to an alleged
commercial bribery committed by us, Gulf Energy Marketing, and Intergen inasmuch
as we, in our role as acquirer of Kinder Morgan Tejas, allegedly paid Intergen
to not renew the underlying Entex contracts belonging to the Tejas/Paz joint
venture. Moreover, new and distinct allegations of breach of fiduciary and
bribery of a fiduciary are also raised in this amended petition for the first
time.
The parties have engaged in some discovery and depositions. At this stage
of discovery, we believe that our actions were justified and defensible under
applicable Texas law and that the decision not to renew the underlying gas sales
agreements was made unilaterally by persons acting on behalf of Entex. The
plaintiffs have moved for summary judgment asking the court to declare that a
fiduciary relationship existed for purposes of Sweatman's claims. We have moved
for summary judgment on the grounds that:
- there is no cause-in-fact of the gas sales nonrenewals attributable to
us; and
- the defense of legal justification applies to the claims for tortuous
interference.
In September 2003 and then again in November 2003, Sweatman and Paz filed
their third and fourth amended petitions, respectively, asserting all of the
claims for relief described above. In addition, the plaintiffs asked that the
court impose a constructive trust on (i) the proceeds of the sale of Tejas and
(ii) any monies received by any Kinder Morgan entity for sales of gas to any
Entex/Reliant entity following June 30, 2002 that replaced volumes of gas
previously sold under contracts to which Sweatman and Paz had a participating
interest pursuant to the joint venture agreement between Tejas, Sweatman and
Paz. In October 2003, the court granted, and then rescinded its order after a
motion to reconsider heard on February 13, 2004, a motion for partial summary
judgment on the issue of the existence of a fiduciary duty.
On October 27, 2004, the court granted a motion for partial summary
judgment in the defendants' favor, finding that, as a matter of law, Sweatman's
interests in four of the five gas sales contracts at issue terminated in 1992
after those contracts were amended in their material terms, and thus falling
outside the joint venture itself. In various forms, the plaintiffs have amended
their petition to allege various oral and implied joint venture agreements as
well as an oral partnership agreement. The claimants are asking for the
imposition of a constructive trust on the proceeds of gas sales contracts with
Entex and its affiliates that were entered into after the gas sales at issue
were unilaterally terminated by Entex on March 28, 2002, for which Sweatman
blames us and our agents and representatives.
We moved for partial summary judgment on all of Sweatman's claims,
asserting that even in the light most favorable to Sweatman's assertions, there
is no issue of material fact on whether Sweatman even owned an interest in the
underlying gas sales agreements in dispute. That motion was heard on August 13,
2004, and was granted on October 26, 2004 as to four of the five gas sales
contracts at issue, leaving for further determination at a later time any
remaining claims based upon other theories of recovery not dependent upon the
four gas sales agreements being joint venture property. We also filed a
no-evidence motion for summary judgment on the plaintiffs' defamation claims.
On March 24, 2005, we announced a settlement of this case. Under the terms
of the settlement, we agreed to pay $25 million to the defendants in full
settlement of any possible claims related to this case. We included this amount
as general and administrative expense in March 2005, and we made payment in
April 2005.
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Maher et ux. v. Centerpoint Energy, Inc., Centerpoint Energy Resources
Corp., Entex Gas Marketing Company, Kinder Morgan Texas Pipeline, L.P., Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Tejas
Pipeline, L.P., Kinder Morgan Tejas Pipeline, GP, Inc., Kinder Morgan Texas
Pipeline GP, Inc., Tejas Gas, LLC, Midcon Corp., Gulf Energy Marketing, LLC,
Houston Pipeline Company, L.P, HPL GP, LLC, and AEP Gas Marketing, L.P., No.
30875 (District Court, Wharton County Texas).
On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan
Energy Partners, L.P. were served with the above-entitled Complaint. A First
Amended Complaint was served on October 23, 2002, adding additional defendants
Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc., Kinder Morgan
Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. A Second Amended
Complaint was filed on January 6, 2003, which added additional proposed
plaintiff class representatives. A Third Amended Complaint was filed on February
4, 2005, which dropped the purported class action allegations and added
additional defendants, Midcon Corp. and Gulf Energy Marketing, LLC. The
Complaint purports to bring an action on behalf of three plaintiffs who
purchased natural gas for residential purposes from the so-called "Centerpoint
defendants" in Texas at any time during the period encompassing "at least the
last ten years."
The Complaint alleges that Centerpoint Energy Resources Corp., by and
through its affiliates, has artificially inflated the price charged to
residential consumers for natural gas that it allegedly purchased from the
non-Centerpoint defendants, including the above-listed Kinder Morgan entities.
The Complaint further alleges that in exchange for Centerpoint Energy Resources
Corp.'s purchase of natural gas at above market prices, the non-Centerpoint
defendants, including the above-listed Kinder Morgan entities, sell natural gas
to Entex Gas Marketing Company at prices substantially below market, which in
turn sells such natural gas to commercial and industrial consumers and gas
marketers at market price. The Complaint purports to assert claims for fraud,
violations of the Texas Deceptive Trade Practices Act, and violations of the
Texas Utility Code against some or all of the defendants, and civil conspiracy
against all of the defendants, and seeks relief in the form of, among other
things, actual, exemplary and statutory damages, civil penalties, interest,
attorneys' fees and a constructive trust ab initio on any and all sums which
allegedly represent overcharges by Centerpoint and Centerpoint Energy Resources
Corp.
On November 18, 2002, the Kinder Morgan defendants filed a Motion to
Transfer Venue and, Subject Thereto, Original Answer to the original Complaint.
On February 10, 2005, the Centerpoint defendants removed the case to the United
States District Court for the Southern District of Texas, Houston Division. On
March 2, 2005, the Centerpoint defendants filed a motion to dismiss the Third
Amended Complaint. On March 16, 2005, all parties stipulated to the dismissal of
the case without prejudice
Weldon Johnson and Guy Sparks , individually and as Representative of
Others Similarly Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2
(Circuit Court, Miller County Arkansas).
On October 8, 2004, plaintiffs filed the above-captioned matter against
numerous defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan
Energy Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder
Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.;
Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC;
and Midcon Corp. (the "Kinder Morgan Defendants"). The Complaint purports to
bring a class action on behalf of those who purchased natural gas from the
Centerpoint defendants from October 1, 1994 to the date of class certification.
The Complaint alleges that Centerpoint Energy, Inc., by and through its
affiliates, has artificially inflated the price charged to residential consumers
for natural gas that it allegedly purchased from the non-Centerpoint defendants,
including the above-listed Kinder Morgan entities. The Complaint further alleges
that in exchange for Centerpoint's purchase of such natural gas at above market
prices, the non-Centerpoint defendants, including the above-listed Kinder Morgan
entities, sell natural gas to Centerpoint's non-regulated affiliates at prices
substantially below market, which in turn sells such natural gas to commercial
and industrial consumers and gas marketers at market price. The Complaint
purports to assert claims for fraud, unlawful enrichment and civil conspiracy
against all of the defendants, and seeks relief in the form of actual, exemplary
and punitive damages, interest, and attorneys' fees. The Complaint was served on
the Kinder Morgan Defendants on October 21, 2004. On November 18, 2004, the
Centerpoint Defendants removed the case to the United States District Court,
Western District of Arkansas, Texarkana Division, Civ. Action No. 04-4154. On
January 26, 2005, the Plaintiffs moved to remand the case back
24
to state court, which motion is currently pending. On December 17, 2004, the
Kinder Morgan Defendants filed a Motion to Dismiss the Complaint, which motion
is also currently pending. Based on the information available to date and our
preliminary investigation, the Kinder Morgan Defendants believe that the claims
against them are without merit and intend to defend against them vigorously.
Marie Snyder, et al v. City of Fallon, United States Department of the
Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas
Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District
Court, District of Nevada)("Snyder"); Frankie Sue Galaz, et al v. United States
of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy
Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No.
cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)("Galaz
I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial District Court,
State of Nevada, County of Washoe) ("Galaz II); Frankie Sue Galaz, et al v. The
United States of America, the City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,
LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services
LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC (United States District
Court, District of Nevada)("Galaz III)
On July 9, 2002, we were served with a purported Complaint for Class Action
in the Snyder case, in which the plaintiffs, on behalf of themselves and others
similarly situated, assert that a leukemia cluster has developed in the City of
Fallon, Nevada. The Complaint alleges that the plaintiffs have been exposed to
unspecified "environmental carcinogens" at unspecified times in an unspecified
manner and are therefore "suffering a significantly increased fear of serious
disease." The plaintiffs seek a certification of a class of all persons in
Nevada who have lived for at least three months of their first ten years of life
in the City of Fallon between the years 1992 and the present who have not been
diagnosed with leukemia.
The Complaint purports to assert causes of action for nuisance and "knowing
concealment, suppression, or omission of material facts" against all defendants,
and seeks relief in the form of "a court-supervised trust fund, paid for by
defendants, jointly and severally, to finance a medical monitoring program to
deliver services to members of the purported class that include, but are not
limited to, testing, preventative screening and surveillance for conditions
resulting from, or which can potentially result from exposure to environmental
carcinogens," incidental damages, and attorneys' fees and costs.
The defendants responded to the Complaint by filing Motions to Dismiss on
the grounds that it fails to state a claim upon which relief can be granted. On
November 7, 2002, the United States District Court granted the Motion to Dismiss
filed by the United States, and further dismissed all claims against the
remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs
filed a Motion for Reconsideration and Leave to Amend, which was denied by the
Court on December 30, 2002. Plaintiffs filed a Notice of Appeal to the United
States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit
affirmed the dismissal of this case.
On December 3, 2002, plaintiffs filed an additional Complaint for Class
Action in the Galaz I matter asserting the same claims in the same court on
behalf of the same purported class against virtually the same defendants,
including us. On February 10, 2003, the defendants filed Motions to Dismiss the
Galaz I Complaint on the grounds that it also fails to state a claim upon which
relief can be granted. This motion to dismiss was granted as to all defendants
on April 3, 2003. Plaintiffs have filed a Notice of Appeal to the United States
Court of Appeals for the 9th Circuit. On November 17, 2003, the 9th Circuit
dismissed the appeal, upholding the District Court's dismissal of the case.
On June 20, 2003, plaintiffs filed an additional Complaint for Class Action
(the "Galaz II" matter) asserting the same claims in Nevada State trial court on
behalf of the same purported class against virtually the same defendants,
including us (and excluding the United States Department of the Navy). On
September 30, 2003, the Kinder Morgan defendants filed a Motion to Dismiss the
Galaz II Complaint along with a Motion for Sanctions. On April 13, 2004,
plaintiffs' counsel voluntarily stipulated to a dismissal with prejudice of the
entire case in State Court. The court has accepted the stipulation and the
parties are awaiting a final order from the court dismissing the case with
prejudice.
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Also on June 20, 2003, the plaintiffs in the previously filed Galaz matters
(now dismissed) filed yet another Complaint for Class Action in the United
States District Court for the District of Nevada (the "Galaz III" matter)
asserting the same claims in United States District Court for the District of
Nevada on behalf of the same purported class against virtually the same
defendants, including us. The Kinder Morgan defendants filed a Motion to Dismiss
the Galaz III matter on August 15, 2003. On October 3, 2003, the plaintiffs
filed a Motion for Withdrawal of Class Action, which voluntarily drops the class
action allegations from the matter and seeks to have the case proceed on behalf
of the Galaz family only. On December 5, 2003, the District Court granted the
Kinder Morgan defendants' Motion to Dismiss, but granted plaintiff leave to file
a second Amended Complaint. Plaintiff filed a Second Amended Complaint on
December 13, 2003, and a Third Amended Complaint on January 5, 2004. The Kinder
Morgan defendants filed a Motion to Dismiss the Third Amended Complaint on
January 13, 2004. The Motion to Dismiss was granted with prejudice on April 30,
2004. On May 7, 2004, Plaintiff filed a Notice of Appeal in the United States
Court of Appeals for the 9th Circuit, which appeal is currently pending.
Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No.
CV03-03482 (Second Judicial District Court, State of Nevada, County of Washoe)
("Jernee").
On May 30, 2003, a separate group of plaintiffs, individually and on behalf
of Adam Jernee, filed a civil action in the Nevada State trial court against us
and several Kinder Morgan related entities and individuals and additional
unrelated defendants ("Jernee"). Plaintiffs in the Jernee matter claim that
defendants negligently and intentionally failed to inspect, repair and replace
unidentified segments of their pipeline and facilities, allowing "harmful
substances and emissions and gases" to damage "the environment and health of
human beings." Plaintiffs claim that "Adam Jernee's death was caused by leukemia
that, in turn, is believed to be due to exposure to industrial chemicals and
toxins." Plaintiffs purport to assert claims for wrongful death, premises
liability, negligence, negligence per se, intentional infliction of emotional
distress, negligent infliction of emotional distress, assault and battery,
nuisance, fraud, strict liability, and aiding and abetting, and seek unspecified
special, general and punitive damages. The Kinder Morgan defendants filed
Motions to Dismiss the complaint on November 20, 2003, which Motions are
currently pending. In addition, plaintiffs and the defendant City of Fallon have
appealed the Trial Court's ruling on initial procedural matters concerning
proper venue. On March 29, 2004, the Nevada Supreme Court stayed the action
pending resolution of these procedural matters on appeal. This appeal is
currently pending.
Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326
(Second Judicial District Court, State of Nevada, County of Washoe) ("Sands").
On August 28, 2003, a separate group of plaintiffs, represented by the
counsel for the plaintiffs in the Jernee matter, individually and on behalf of
Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court
against us and several Kinder Morgan related entities and individuals and
additional unrelated defendants ("Sands"). Plaintiffs in the Sands matter claim
that defendants negligently and intentionally failed to inspect, repair and
replace unidentified segments of their pipeline and facilities, allowing
"harmful substances and emissions and gases" to damage "the environment and
health of human beings." Plaintiffs claim that Stephanie Suzanne Sands' death
was caused by leukemia that, in turn, is believed to be due to exposure to
industrial chemicals and toxins. Plaintiffs purport to assert claims for
wrongful death, premises liability, negligence, negligence per se, intentional
infliction of emotional distress, negligent infliction of emotional distress,
assault and battery, nuisance, fraud, strict liability, and aiding and abetting,
and seek unspecified special, general and punitive damages. The Kinder Morgan
defendants were served with the Complaint on January 10, 2004. On February 26,
2004, the Kinder Morgan defendants filed a Motion to Dismiss and a Motion to
Strike, which motions are currently pending. In addition, plaintiffs and the
defendant City of Fallon have appealed the Trial Court's ruling on initial
procedural matters concerning proper venue and a peremptory challenge of the
trial judge by the plaintiffs. On April 27, 2004, the Nevada Supreme Court
stayed the action pending resolution of these procedural matters on appeal. This
appeal is currently pending.
Based on the information available to date, our own preliminary
investigation, and the positive results of investigations conducted by State and
Federal agencies, we believe that the claims against us in these matters are
without merit and intend to defend against them vigorously.
26
Meritage Homes Corp., Monterey Homes Construction, Inc., and Monterey Homes
Arizona, Inc. v. Kinder Morgan Energy Partners, L.P. and SFPP Limited
Partnership, No. CIV 05 021 TUCCKJ, United States District Court, Arizona.
On January 28, 2005, Meritage Homes Corp. and its above-named affiliates
filed a Complaint in the above-entitled action against us and SFPP, LP. The
Plaintiffs are homebuilders who constructed a subdivision known as Silver Creek
II located in Tucson, Arizona. Plaintiffs allege that, as a result of a July 30,
2003 pipeline rupture and accompanying release of petroleum products, soil and
groundwater adjacent to, on and underlying portions of Silver Creek II became
contaminated. Plaintiffs allege that they have incurred and continue to incur
costs, damages and expenses associated with the delay of closings of home sales
within Silver Creek II and damage to their reputation and goodwill as a result
of the rupture and release. Plaintiffs' complaint purports to assert claims for
negligence, breach of contract, trespass, nuisance, strict liability,
subrogation and indemnity, and negligence per se. Plaintiffs seek "no less than
$1,500,000 in compensatory damages and necessary response costs," a declaratory
judgment, interest, punitive damages and attorneys' fees and costs. The parties
have agreed to submit the claims to arbitration and are currently negotiating an
arbitration schedule. We dispute the legal and factual bases for many of
Plaintiffs' claimed compensatory damages, deny that punitive damages are
appropriate under the facts, and intend to vigorously defend this action.
Walnut Creek, California Pipeline Rupture
On November 9, 2004, Mountain Cascade, Inc., a third-party contractor on a
water main replacement project hired by East Bay Municipal Utility District,
struck and ruptured an underground petroleum pipeline owned and operated by
SFPP, LP in Walnut Creek, California. An explosion occurred immediately
following the rupture that resulted in five fatalities and several injuries to
employees or contractors of Mountain Cascade.
On May 5, 2005, the California Division of Occupational Safety and Health
("CalOSHA") issued two citations against us relating to this incident assessing
fines of $140,000 based upon our alleged failure to mark the location of the
pipeline properly prior to the excavation of the site by the contractor. The
location of the incident was not our work site, not did we have any direct
involvement in the project. We believe that SFPP acted in accordance with
applicable California law, and further that according to California law,
excavators, such as the contractor on the project, must take the necessary steps
(including excavating with hand tools) to confirm the exact location of a
pipeline before using any power operated or power driven excavation equipment.
Accordingly, we disagree with the findings of CalOSHA and plan to appeal the
citations.
Juana Lilian Arias, et. al v. Kinder Morgan, Inc., Kinder Morgan Energy
Partners, L.P., Mountain Cascade, Inc., and Does 1-30, No. RG05195567 (Superior
Court, Alameda County, California).
The above-referenced complaint for personal injuries and wrongful death was
filed on January 26, 2005. Plaintiffs allege that Victor Javier Rodriguez was
killed as a result of the rupture by Mountain Cascade, Inc. of SFPP, LP's
petroleum pipeline in Walnut Creek, California and the resulting explosion and
fire. Plaintiffs allege that defendants failed to properly locate and mark the
location of the petroleum pipeline. The complaint purports to assert claims for
negligence, unfair competition, strict liability and intentional
misrepresentation. Plaintiffs seek unspecified general damages, incidental
damages, economic damages, disgorgement of profits, exemplary damages, interest,
attorneys' fees and costs.
Marilu Angeles, et. al v. Kinder Morgan, Inc., Kinder Morgan Energy
Partners, L.P., Mountain Cascade, Inc., Does 1-30 and Mariel Hernandez, No.
RG05195680 (Superior Court, Alameda County, California).
The above-referenced complaint for personal injuries and wrongful death was
filed on January 26, 2005. Plaintiffs allege that Israel Hernandez was killed as
a result of the rupture by Mountain Cascade, Inc. of SFPP, LP's petroleum
pipeline in Walnut Creek, California and the resulting explosion and fire.
Plaintiffs allege that defendants failed to properly locate and mark the
location of the petroleum pipeline. The complaint purports to assert claims for
negligence, unfair competition, strict liability and intentional
misrepresentation. Plaintiffs seek unspecified general damages, incidental
damages, economic damages, disgorgement of profits, exemplary damages, interest,
attorneys' fees and costs.
Jeremy and Johanna Knox v. Mountain Cascade, Inc, Kinder Morgan Energy
Partners of Houston, Inc., and Does 1 to 50, No. C 05-00281 (Superior Court,
Contra Costa County, California).
The above-referenced complaint for personal injuries was filed on February
2, 2005. Plaintiffs allege that Jeremy Knox was injured as a result of the
rupture by Mountain Cascade, Inc. of SFPP, LP's petroleum pipeline in Walnut
Creek, California and the resulting explosion and fire. Plaintiffs allege that
defendants failed to properly locate and mark the location of the petroleum
pipeline. Plaintiffs assert claims for negligence, loss of consortium, and
exemplary damages in an unspecified amount.
27
Laura Reyes et. al. v. East Bay Municipal Utility District, Mountain
Cascade, Inc. and Kinder Morgan Energy Partners, L.P.
We understand that the above-referenced complaint was filed on or about
April 14, 2005. As of April 30, 2005, we had not yet been served with a copy of
the complaint. We understand that the suit was filed on behalf of Laura Reyes,
wife of deceased welder Miguel Reyes, and their three minor children, and that
the complaint includes claims of wrongful death and negligence, and seeks
unspecified compensatory and punitive damages.
Based upon our initial investigation of the cause of the rupture of SFPP,
LP's petroleum pipeline by Mountain Cascade, Inc. and the resulting explosion
and fire, we intend to deny liability for the resulting deaths, injuries and
damages, to vigorously defend against such claims, and to seek contribution and
indemnity from the responsible parties.
Marion County, Mississippi Litigation
In 1968, Plantation Pipe Line Company discovered a release from its 12-inch
pipeline in Marion County, Mississippi. The pipeline was immediately repaired.
In 1998 and 1999, 62 lawsuits were filed on behalf of 263 plaintiffs in the
Circuit Court of Marion County, Mississippi. The majority of the claims are
based on alleged exposure from the 1968 release, including claims for property
damage and personal injury. During the first quarter of 2005, settlements and/or
dismissals were completed with all of the plaintiffs.
Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids
Terminals, Inc. and ST Services, Inc.
On April 23, 2003, Exxon Mobil Corporation filed the Complaint in the
Superior Court of New Jersey, Gloucester County. We filed our answer to the
Complaint on June 27, 2003, in which we denied ExxonMobil's claims and
allegations as well as included counterclaims against ExxonMobil. The lawsuit
relates to environmental remediation obligations at a Paulsboro, New Jersey
liquids terminal owned by ExxonMobil from the mid-1950s through November 1989,
by GATX Terminals Corp. from 1989 through September 2000, and owned currently by
ST Services, Inc. Prior to selling the terminal to GATX Terminals, ExxonMobil
performed an environmental site assessment of the terminal required prior to
sale pursuant to state law. During the site assessment, ExxonMobil discovered
items that required remediation and the New Jersey Department of Environmental
Protection issued an order that required ExxonMobil to perform various
remediation activities to remove hydrocarbon contamination at the terminal.
ExxonMobil, we understand, is still remediating the site and has not been
removed as a responsible party from the state's cleanup order; however,
ExxonMobil claims that the remediation continues because of GATX Terminals'
storage of a fuel additive, MTBE, at the terminal during GATX Terminals'
ownership of the terminal. When GATX Terminals sold the terminal to ST Services,
the parties indemnified one another for certain environmental matters. When GATX
Terminals was sold to us, GATX Terminals' indemnification obligations, if any,
to ST Services may have passed to us. Consequently, at issue is any
indemnification obligations we may owe to ST Services in respect to
environmental remediation of MTBE at the terminal. The Complaint seeks any and
all damages related to remediating MTBE at the terminal, and, according to the
New Jersey Spill Compensation and Control Act, treble damages may be available
for actual dollars incorrectly spent by the successful party in the lawsuit for
remediating MTBE at the terminal. The parties have recently completed discovery.
In October 2004, the judge assigned to the case dismissed himself from the case
based on a conflict, and the new judge has ordered the parties to participate in
mandatory mediation. The mediation is currently scheduled for May 2005.
Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party
in interest for Enron Helium Company, a division of Enron Corp., Enron Liquids
Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder
Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252 (189th
Judicial District Court, Harris County, Texas)
On September 1, 2000, Plaintiff Exxon Mobil Corporation filed its Original
Petition and Application for Declaratory Relief against Kinder Morgan Operating
L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder
Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P.,
Inc.,
28
Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron Helium
Company. Plaintiff added Enron Corp. as party in interest for Enron Helium
Company in its First Amended Petition and added Kinder Morgan, Inc. as a
Defendant. The claims against Enron Corp. were severed into a separate cause of
action. Plaintiff's claims are based on a Gas Processing Agreement entered into
on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company
relating to gas produced in the Hugoton Field in Kansas and processed at the
Bushton Plant, a natural gas processing facility located in Kansas. Plaintiff
also asserts claims relating to the Helium Extraction Agreement entered between
Enron Helium Company (a division of Enron Corp.) and Mobil Oil Corporation dated
March 14, 1988. Plaintiff alleges that Defendants failed to deliver propane and
to allocate plant products to Plaintiff as required by the Gas Processing
Agreement and originally sought damages of approximately $5.9 million.
Plaintiff filed its Third Amended Petition on February 25, 2003. In its
Third Amended Petition, Plaintiff alleges claims for breach of the Gas
Processing Agreement and the Helium Extraction Agreement, requests a declaratory
judgment and asserts claims for fraud by silence/bad faith, fraudulent
inducement of the 1997 Amendment to the Gas Processing Agreement, civil
conspiracy, fraud, breach of a duty of good faith and fair dealing, negligent
misrepresentation and conversion. As of April 7, 2003, Plaintiff alleged
economic damages for the period from November 1987 through March 1997 in the
amount of $30.7 million. On May 2, 2003, Plaintiff added claims for the period
from April 1997 through February 2003 in the amount of $12.9 million. On June
23, 2003, Plaintiff filed a Fourth Amended Petition that reduced its total claim
for economic damages to $30.0 million. On October 5, 2003, Plaintiff filed a
Fifth Amended Petition that purported to add a cause of action for embezzlement.
On February 10, 2004, Plaintiff filed its Eleventh Supplemental Responses to
Requests for Disclosure that restated its alleged economic damages for the
period of November 1987 through December 2003 as approximately $37.4 million.
The matter went to trial on June 21, 2004. On June 30, 2004, the jury returned a
unanimous verdict in favor of all defendants as to all counts. Final Judgment
was entered in favor of the defendants on August 19, 2004. Plaintiff has
appealed the jury's verdict to the 14th Court of Appeals for the State of Texas.
Briefing on the appeal is scheduled to be completed in September 2005.
Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions, that, to the extent an assessment of the
matter is possible, we have established an adequate reserve to cover potential
liability, and that these matters will not have a material adverse effect on our
business, financial position, results of operations or cash flows.
Proposed Office of Pipeline Safety Civil Penalty and Compliance Order
On July 15, 2004, the U.S. Department of Transportation's Office of
Pipeline Safety ("OPS") issued a Proposed Civil Penalty and Proposed Compliance
Order (the "Proposed Order") concerning alleged violations of certain federal
regulations concerning our pipeline Integrity Management Program. The violations
alleged in the Proposed Order are based upon the results of inspections of our
Integrity Management Program at our products pipelines facilities in Orange,
California and Doraville, Georgia conducted in April and June of 2003,
respectively. As a result of the alleged violations, the OPS seeks to have us
implement a number of changes to our Integrity Management Program and also seeks
to impose a proposed civil penalty of approximately $0.3 million. We have
already addressed a number of the concerns identified by the OPS and intend to
continue to work with the OPS to ensure that our Integrity Management Program
satisfies all applicable regulations. However, we dispute some of the OPS
findings and disagree that civil penalties are appropriate, and therefore have
requested an administrative hearing on these matters according to the U.S.
Department of Transportation regulations. An administrative hearing was held on
April 11 and 12, 2005. Supplemental information will be provided to the hearing
officer within thirty days by both the OPS and us. It is anticipated that the
decision in this matter and potential administrative order will be issued late
in the second quarter of 2005 or in the third quarter of 2005.
Environmental Matters
We are subject to environmental cleanup and enforcement actions from time
to time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) generally imposes joint and several
liability for cleanup and enforcement costs on current or predecessor owners and
operators of a site, among others, without regard to fault or the legality of
the original conduct. Our operations are also subject to federal, state and
local laws and regulations relating to protection of the environment. Although
we believe our operations are in
29
substantial compliance with applicable environmental law and regulations, risks
of additional costs and liabilities are inherent in pipeline, terminal and
carbon dioxide field and oil field operations, and there can be no assurance
that we will not incur significant costs and liabilities. Moreover, it is
possible that other developments, such as increasingly stringent environmental
laws, regulations and enforcement policies thereunder, and claims for damages to
property or persons resulting from our operations, could result in substantial
costs and liabilities to us.
We are currently involved in the following governmental proceedings related
to compliance with environmental regulations associated with our assets and have
established a reserve to address the costs associated with the cleanup:
- several groundwater and soil remediation efforts under administrative
orders or related state remediation programs issued by the California
Regional Water Quality Control Board and several other state agencies
for assets associated with SFPP, L.P.;
- groundwater and soil remediation efforts under administrative orders
issued by various regulatory agencies on those assets purchased from
GATX Corporation, comprising Kinder Morgan Liquids Terminals LLC, KM
Liquids Terminals L.P., CALNEV Pipe Line LLC and Central Florida
Pipeline LLC;
- groundwater and soil remediation efforts under administrative orders
or related state remediation programs issued by various regulatory
agencies on those assets purchased from ExxonMobil; ConocoPhillips;
and Charter Triad, comprising Kinder Morgan Southeast Terminals, LLC.;
and
- groundwater and soil remediation efforts under administrative orders
or related state remediation programs issued by various regulatory
agencies on those assets comprising Plantation Pipe Line Company,
including a ground water remediation effort taking place between
Chevron, Plantation Pipe Line Company and the Alabama Department of
Environmental Management.
Tucson, Arizona
On July 30, 2003, SFPP, L.P. suffered a sudden and accidental rupture of
one of its liquid products pipelines in the vicinity of Tucson, Arizona. The
rupture resulted in the release of petroleum product into the soil and
groundwater in the immediate vicinity of the rupture.
On September 11, 2003, the Arizona Department of Environmental Quality
("ADEQ") issued a Notice of Violation indicating that ADEQ "has reason to
believe" that SFPP violated certain Arizona statutes and rules due to the
discharge of petroleum product to the environment as a result of the pipeline
rupture. ADEQ asserted that such alleged violations could result in the
imposition of civil penalties against SFPP. SFPP timely responded to the Notice
of Violation, disputed its validity, and provided the information requested in
the Notice of Violation. According to ADEQ written policy, a Notice of Violation
is not an enforcement action, and is instead "an enforcement compliance
assurance tool used by ADEQ." ADEQ's policy also states that although ADEQ has
the "authority to issue appealable administrative orders compelling compliance,
a Notice of Violation has no such force or effect."
On November 13, 2003, ADEQ sent a second Notice of Violation with respect
to the pipeline rupture and release, stating that ADEQ had reason to believe
that a violation of additional Arizona regulations had resulted from the
discharge of petroleum, because the petroleum had reached groundwater. ADEQ
asserted that such alleged violations could result in the imposition of civil
penalties against SFPP. SFPP timely responded to this second Notice of
Violation, disputed its validity, and provided the information requested in the
second Notice of Violation.
On January 19, 2005, SFPP, L.P. and ADEQ announced a settlement with the
terms of the settlement set forth in a consent judgment filed with the Maricopa
County Superior Court. Under the terms of the settlement, we paid $500,000 to
the State of Arizona in full settlement of any possible claims by the state
arising out of the release. The settlement expressly provides that we do not
admit any wrongdoing or violation of environmental law. On April 12, 2005, the
ADEQ filed a Satisfaction of Judgment with the Maricopa County Superior Court
acknowledging full satisfaction of the Consent Judgment and terminating the
Consent Judgment. We are currently evaluating the long term costs of the
cleanup. A substantial portion of those costs are recoverable through insurance.
30
Cordelia, California
On April 28, 2004, we discovered a spill of diesel fuel into a marsh near
Cordelia, California from a section of our Pacific operations' 14-inch Concord
to Sacramento, California products pipeline. Estimates indicated that the size
of the spill was approximately 2,450 barrels. Upon discovery of the spill and
notification to regulatory agencies, a unified response was implemented with the
United States Coast Guard, the California Department of Fish and Game, the
Office of Spill Prevention and Response and us. The damaged section of the
pipeline was removed and replaced, and the pipeline resumed operations on May 2,
2004. We have completed recovery of free flowing diesel from the marsh and have
completed an enhanced biodegradation program for removal of the remaining
constituents bound up in soils. The property has been turned back to the owners
for its stated purpose. There will be ongoing monitoring under the oversight of
the California Regional Water Quality Control Board until the site conditions
demonstrate there are no further actions required. We are currently in
negotiations with the United States Environmental Protection Agency, the United
States Fish & Wildlife Service, the California Department of Fish & Game and the
San Francisco Regional Water Quality Control Board regarding potential civil
penalties and natural resource damages assessments.
In April 2005, we were informed by the office of the Attorney General of
California that the office was contemplating filing criminal charges against us
claiming discharge of diesel fuel arising from the April 2004 rupture from a
section of our Pacific operations' 14-inch Concord to Sacramento, California
products pipeline and the failure to make timely notice of the discharge to
appropriate state agencies. In addition, we were told that the California
Attorney General was also contemplating filing charges alleging other releases
and failures to provide timely notice regarding certain environmental incidents
at certain of our facilities in California.
On April 26, 2005, we announced that we had entered into an agreement with
the Attorney General of the State of California and the District Attorney of
Solano County, California, to settle misdemeanor charges of the unintentional,
non-negligent discharge of diesel fuel resulting from this release and the
failure to provide timely notice of a threatened discharge to appropriate state
agencies as well as other potential claims in California regarding alleged
notice and discharge incidents. In addition to the charges settled by this
agreement, we entered into an agreement in principle to settle similar
additional misdemeanor charges in Los Angeles County, California, in connection
with the unintentional, non-negligent release of approximately five gallons of
diesel fuel at our Carson refined petroleum products terminal in Los Angeles
Harbor in May 2004.
Under the settlement agreement related to the Cordelia, California
incident, SFPP, L.P. agreed to plead guilty to four misdemeanors and to pay
approximately $5.2 million in fines, penalties, restitution, environmental
improvement project funding, and enforcement training in the State of
California, and agreed to be placed on informal, unsupervised probation for a
term of three years. Under the settlement agreement related to the Carson
terminal incident, Kinder Morgan Liquids Terminals LLC agreed to plead guilty to
two additional misdemeanors and to pay approximately $0.2 million in fines and
penalties. We included the combined $5.4 million as general and administrative
expense in March 2005, and we have made payments in the amount of $0.3 million
as of March 31, 2005. We expect to pay the remaining $5.1 million in the second
quarter of 2005. Since the April 2004 release in the Suisun Marsh area near
Cordelia, California, we have cooperated fully with federal and state agencies
and have worked diligently to remediate the affected areas. As of April 30,
2005, the remediation is substantially complete.
San Diego, California
In June 2004, we entered into discussions with the City of San Diego with
respect to impacted groundwater beneath the City's stadium property in San Diego
resulting from operations at the Mission Valley terminal facility. The City has
requested that SFPP work with the City as they seek to re-develop options for
the stadium area including future use of both groundwater aquifer and real
estate development. The City of San Diego and SFPP are working cooperatively
towards a settlement and a long-term plan as SFPP continues to remediate the
impacted groundwater. We do not expect the cost of any settlement and
remediation plan to be material. This site has been, and currently is, under the
regulatory oversight and order of the California Regional Water Quality Control
Board.
31
Baker, California
In November 2004, our CALNEV pipeline, which transports refined petroleum
products from Colton, California to Las Vegas, Nevada, experienced a failure in
the line from external damage, resulting in a release of gasoline that affected
approximately two acres of land in the high desert administered by The Bureau of
Land Management, an agency within the U.S. Department of the Interior.
Remediation has been conducted and continues for product in the soils. All
agency requirements have been met and the site will be closed upon completion of
the soil remediation.
Oakland, California
In February 2005, we were contacted by the U.S. Coast Guard regarding a
potential release of jet fuel in the Oakland, California area. Our northern
California team responded and discovered that one of our product pipelines had
been damaged by a third party, which resulted in a release of jet fuel which
migrated to the storm drain system. We have coordinated the remediation of the
impacts from this release.
Donner Summit, California
In April 2005, our SFPP pipeline in Northern California, which transports
refined petroleum products to Reno, Nevada, experienced a failure in the line
from external damage, resulting in a release of product that affected a limited
area adjacent to the pipeline near the summit of Donner Pass. The release was
located on land administered by the Forest Service, an agency within the U.S.
Department of Agriculture. Initial remediation has been conducted in the
immediate vicinity of the pipeline. All agency requirements have been met and
the site will be closed upon completion of the remediation.
Other Environmental
On March 30, 2004, the Texas Commission on Environmental Quality (TCEQ)
issued a Notice of Enforcement Action related to our CO2 segment's Snyder Gas
Plant. We are currently in final settlement discussions with TCEQ regarding this
issue and do not expect the cost of any settlement to be material. In addition,
we are from time to time involved in civil proceedings relating to damages
alleged to have occurred as a result of accidental leaks or spills of refined
petroleum products, natural gas liquids, natural gas and carbon dioxide.
Our review of assets related to Kinder Morgan Interstate Gas Transmission
LLC indicates possible environmental impacts from petroleum and used oil
releases into the soil and groundwater at nine sites. Additionally, our review
of assets related to Kinder Morgan Texas Pipeline and Kinder Morgan Tejas
indicates possible environmental impacts from petroleum releases into the soil
and groundwater at nine sites. Further delineation and remediation of any
environmental impacts from these matters will be conducted. Reserves have been
established to address these issues.
We are also involved with and have been identified as a potentially
responsible party in several federal and state superfund sites. Environmental
reserves have been established for those sites where our contribution is
probable and reasonably estimable.
Although no assurance can be given, we believe that the ultimate resolution
of the environmental matters set forth in this note will not have a material
adverse effect on our business, financial position, results of operations or
cash flows. However, we are not able to reasonably estimate when the eventual
settlements of these claims will occur. Many factors may change in the future
affecting our reserve estimates, such as regulatory changes, groundwater and
land use near our sites, and changes in cleanup technology. As of March 31,
2005, we have accrued an environmental reserve of $36.6 million.
Other
We are a defendant in various lawsuits arising from the day-to-day
operations of our businesses. Although no assurance can be given, we believe,
based on our experiences to date, that the ultimate resolution of such items
will not have a material adverse impact on our business, financial position,
results of operations or cash flows.
32
4. Asset Retirement Obligations
We account for our legal obligations associated with the retirement of
long-lived assets pursuant to Statement of Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides
accounting and reporting guidance for legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction
or normal operation of a long-lived asset.
SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. Under SFAS No. 143,
the fair value of asset retirement obligations are recorded as liabilities on a
discounted basis when they are incurred, which is typically at the time the
assets are installed or acquired. Amounts recorded for the related assets are
increased by the amount of these obligations. Over time, the liabilities will be
accreted for the change in their present value and the initial capitalized costs
will be depreciated over the useful lives of the related assets. The liabilities
are eventually extinguished when the asset is taken out of service.
In our CO2 business segment, we are required to plug and abandon oil and
gas wells that have been removed from service and to remove our surface wellhead
equipment and compressors. As of March 31, 2005, we have recognized asset
retirement obligations in the aggregate amounts of $35.3 million relating to
these requirements at existing sites within our CO2 business segment.
In our Natural Gas Pipelines business segment, if we were to cease
providing utility services, we would be required to remove surface facilities
from land belonging to our customers and others. Our Texas intrastate natural
gas pipeline group has various condensate drip tanks and separators located
throughout its natural gas pipeline systems, as well as inactive gas processing
plants, laterals and gathering systems which are no longer integral to the
overall mainline transmission systems, and asbestos-coated underground pipe
which is being abandoned and retired. Our Kinder Morgan Interstate Gas
Transmission system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of March 31, 2005, we have recognized asset
retirement obligations in the aggregate amounts of $3.0 million relating to the
businesses within our Natural Gas Pipelines business segment.
We have included $0.8 million of our total asset retirement obligations as
of March 31, 2005 with "Accrued other current liabilities" in our accompanying
consolidated balance sheet. The remaining $37.5 million obligation is reported
separately as a non-current liability. No assets are legally restricted for
purposes of settling our asset retirement obligations. A reconciliation of the
beginning and ending aggregate carrying amount of our asset retirement
obligations for each of the three months ended March 31, 2005 and 2004 is as
follows (in thousands):
Three Months Ended March 31,
----------------------------
2005 2004
--------- -----------
Balance at beginning of period........... $ 38,274 $ 35,708
Liabilities incurred..................... (238) -
Liabilities settled...................... (233) (230)
Accretion expense........................ 520 519
Revisions in estimated cash flows........ - -
--------- -----------
Balance at end of period................. $ 38,323 $ 35,997
========= ===========
5. Distributions
On February 14, 2005, we paid a cash distribution of $0.74 per unit to our
common unitholders and our Class B unitholders for the quarterly period ended
December 31, 2004. KMR, our sole i-unitholder, received 955,936 additional
i-units based on the $0.74 cash distribution per common unit. The distributions
were declared on January 18, 2005, payable to unitholders of record as of
January 31, 2005.
On April 20, 2005, we declared a cash distribution of $0.76 per unit for
the quarterly period ended March 31, 2005. The distribution will be paid on May
13, 2005, to unitholders of record as of April 29, 2005. Our common
33
unitholders and Class B unitholders will receive cash. KMR will receive a
distribution in the form of additional i-units based on the $0.76 distribution
per common unit. The number of i-units distributed will be 963,496. For each
outstanding i-unit that KMR holds, a fraction of an i-unit (0.017482) will be
issued. The fraction was determined by dividing:
- $0.76, the cash amount distributed per common unit
by
- $43.473, the average of KMR's limited liability shares' closing market
prices from April 13-26, 2005, the ten consecutive trading days
preceding the date on which the shares began to trade ex-dividend
under the rules of the New York Stock Exchange.
6. Intangibles
Our intangible assets include goodwill, lease value, contracts and
agreements. All of our intangible assets having definite lives are being
amortized on a straight-line basis over their estimated useful lives. Following
is information related to our intangible assets still subject to amortization
and our goodwill (in thousands):
March 31, December 31,
2005 2004
----------- -----------
Goodwill
Gross carrying amount...... $ 760,068 $ 746,980
Accumulated amortization... (14,142) (14,142)
----------- -----------
Net carrying amount........ 745,926 732,838
----------- -----------
Lease value
Gross carrying amount...... 6,592 6,592
Accumulated amortization... (1,064) (1,028)
----------- -----------
Net carrying amount........ 5,528 5,564
----------- -----------
Contracts and other
Gross carrying amount...... 35,167 10,775
Accumulated amortization... (1,385) (1,055)
----------- -----------
Net carrying amount........ 33,782 9,720
----------- -----------
Total intangibles, net..... $ 785,236 $ 748,122
=========== ===========
Changes in the carrying amount of goodwill for the three months ended March
31, 2005 are summarized as follows (in thousands):
Products Natural Gas
Pipelines Pipelines CO2 Terminals Total
----------- ------------ ----------- ----------- -----------
Balance as of December 31, 2004.... $ 263,182 $ 250,318 $ 46,101 $ 173,237 $ 732,838
Acquisitions..................... 13,088 - - - 13,088
Disposals - purchase price adjs.. - - - - -
Impairments...................... - - - - -
----------- ------------ ----------- ----------- -----------
Balance as of March 31, 2005....... $ 276,270 $ 250,318 $ 46,101 $ 173,237 $ 745,926
=========== =========== =========== =========== ===========
Amortization expense on our intangibles consisted of the following (in
thousands):
Three Months Ended March 31,
------------------------------
2005 2004
------------ ------------
Lease value............ $ 36 $ 36
Contracts and other.... 330 125
------------ ------------
Total amortization..... $ 366 $ 161
=========== ===========
As of March 31, 2005, our weighted average amortization period for our
intangible assets was approximately 26.9 years. Our estimated amortization
expense for these assets for each of the next two fiscal years is approximately
$1.3 million, and for each of the following three fiscal years, approximately
$1.0 million.
34
In addition, pursuant to ABP No. 18, any premium paid by an investor, which
is analogous to goodwill, must be identified. The premium, representing excess
cost over underlying fair value of net assets accounted for under the equity
method of accounting, is referred to as equity method goodwill, and is not
subject to amortization but rather to impairment testing. The impairment test
under APB No. 18 considers whether the fair value of the equity investment as a
whole, not the underlying net assets, has declined and whether that decline is
other than temporary. This test requires equity method investors to continue to
assess impairment of investments in investees by considering whether declines in
the fair values of those investments, versus carrying values, may be other than
temporary in nature. As of both March 31, 2005 and December 31, 2004, we have
reported $150.3 million in equity method goodwill within the caption
"Investments" in our accompanying consolidated balance sheets.
7. Debt
Our outstanding short-term debt as of March 31, 2005 was $267.2 million.
The balance consisted of:
- $263.4 million of commercial paper borrowings;
- $5 million of 7.84% Senior Notes (our subsidiary, Central Florida Pipe
Line LLC, is the obligor on the notes); and
- an offset of $1.2 million (which represents the net of other
borrowings and the accretion of discounts on our senior note
issuances).
As of March 31, 2005, we intended and had the ability to refinance all of
our short-term debt on a long-term basis under our unsecured long-term credit
facility. Accordingly, such amounts have been classified as long-term debt in
our accompanying consolidated balance sheet.
The weighted average interest rate on all of our borrowings was
approximately 4.901% during the first quarter of 2005 and 4.385% during the
first quarter of 2004.
Credit Facility
As of March 31, 2005, we had a $1.25 billion five-year, unsecured revolving
credit facility due August 18, 2009. Similar to our previous credit facilities,
our current credit facility is with a syndicate of financial institutions and
Wachovia Bank, National Association is the administrative agent. There were no
borrowings under our five-year credit facility as of March 31, 2005 or as of
December 31, 2004.
The amount available for borrowing under our credit facility as of March
31, 2005 was reduced by:
- our outstanding commercial paper borrowings ($263.4 million as of
March 31, 2005);
- a combined $248 million in two letters of credit that support our
hedging of commodity price risks involved from the sale of natural
gas, natural gas liquids, oil and carbon dioxide;
- a combined $50 million in two letters of credit that support
tax-exempt bonds; and
- $1.5 million of other letters of credit supporting other obligations
of us and our subsidiaries.
Interest Rate Swaps
Information on our interest rate swaps is contained in Note 10.
35
Commercial Paper Program
As of both March 31, 2005 and December 31, 2004, our commercial paper
program provided for the issuance of up to $1.25 billion of commercial paper. As
of March 31, 2005, we had $263.4 million of commercial paper outstanding with an
average interest rate of 2.6798%. Borrowings under our commercial paper program
reduce the borrowings allowed under our credit facility.
Senior Notes
On March 15, 2005, we paid $200 million to retire the principal amount of
our 8.0% senior notes that matured on that date. We borrowed the necessary funds
under our commercial paper program.
On March 15, 2005, we closed a public offering of $500 million in principal
amount of 5.80% senior notes due March 15, 2035 at a price to the public of
99.746% per note. In the offering, we received proceeds, net of underwriting
discounts and commissions, of approximately $494.4 million. We used the proceeds
to reduce the outstanding balance on our commercial paper borrowings.
International Marine Terminals Debt
Since February 1, 2002, we have owned a 66 2/3% interest in International
Marine Terminals partnership. The principal assets owned by IMT are dock and
wharf facilities financed by the Plaquemines Port, Harbor and Terminal District
(Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities Revenue
Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B.
On March 15, 2005, these bonds were refunded and the maturity date was
extended from March 15, 2006 to March 15, 2025. No other changes were made under
the bond provisions. The bonds are backed by two letters of credit issued by KBC
Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit
Reimbursement Agreement relating to the letters of credit in the amount of $45.5
million was entered into by IMT and KBC Bank. In connection with that agreement,
we agreed to guarantee the obligations of IMT in proportion to our ownership
interest. Our obligation is approximately $30.3 million for principal, plus
interest and other fees.
Contingent Debt
We apply the provisions of Financial Accounting Standards Board
Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements
for Guarantees, Including Indirect Guarantees of Indebtedness of Others" to our
agreements that contain guarantee or indemnification clauses. These disclosure
provisions expand those required by SFAS No. 5, "Accounting for Contingencies,"
by requiring a guarantor to disclose certain types of guarantees, even if the
likelihood of requiring the guarantor's performance is remote. The following is
a description of our contingent debt agreements.
Cortez Pipeline Company Debt
Pursuant to a certain Throughput and Deficiency Agreement, the partners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% partner; a
subsidiary of Exxon Mobil Corporation - 37% partner; and Cortez Vickers Pipeline
Company - 13% partner) are required, on a several, percentage ownership basis,
to contribute capital to Cortez Pipeline Company in the event of a cash
deficiency. The Throughput and Deficiency Agreement contractually supports the
borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez
Pipeline Company, by obligating the partners of Cortez Pipeline Company to fund
cash deficiencies at Cortez Pipeline Company, including cash deficiencies
relating to the repayment of principal and interest on borrowings by Cortez
Capital Corporation. Parent companies of the respective Cortez Pipeline Company
partners further severally guarantee, on a percentage basis, the obligations of
the Cortez Pipeline Company partners under the Throughput and Deficiency
Agreement.
Due to our indirect ownership of Cortez Pipeline Company through Kinder
Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez
Capital Corporation. Shell Oil Company shares our several guaranty obligations
jointly and severally; however, we are obligated to indemnify Shell for
liabilities it incurs in connection
36
with such guaranty. With respect to Cortez's long-term revolving credit
facility, Shell is released of its guaranty obligations on December 31, 2006.
Furthermore, with respect to Cortez's short-term commercial paper program and
Series D notes, we must use commercially reasonable efforts to have Shell
released of its guaranty obligations by December 31, 2006. If we are unable to
obtain Shell's release in respect of the Series D Notes by that date, we are
required to provide Shell with collateral (a letter of credit, for example) to
secure our indemnification obligations to Shell.
As of March 31, 2005, the debt facilities of Cortez Capital Corporation
consisted of:
- $85 million of Series D notes due May 15, 2013;
- a $125 million short-term commercial paper program; and
- a $125 million five-year committed revolving credit facility due
December 22, 2009 (to support the above-mentioned $125 million
commercial paper program).
As of March 31, 2005, Cortez Capital Corporation had $105.4 million of
commercial paper outstanding with an average interest rate of 2.6868%, the
average interest rate on the Series D notes was 7.0835%, and there were no
borrowings under the credit facility.
Red Cedar Gas Gathering Company Debt
In October 1998, Red Cedar Gas Gathering Company sold $55 million in
aggregate principal amount of Senior Notes due October 31, 2010. The $55 million
was sold in 10 different notes in varying amounts with identical terms.
The Senior Notes are collateralized by a first priority lien on the
ownership interests, including our 49% ownership interest, in Red Cedar Gas
Gathering Company. The Senior Notes are also guaranteed by us and the other
owner of Red Cedar Gas Gathering Company jointly and severally. The principal is
to be repaid in seven equal installments beginning on October 31, 2004 and
ending on October 31, 2010. As of March 31, 2005, $47.1 million in principal
amount of notes were outstanding.
Nassau County, Florida Ocean Highway and Port Authority Debt
Nassau County, Florida Ocean Highway and Port Authority is a political
subdivision of the State of Florida. During 1990, Ocean Highway and Port
Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal
amount of $38.5 million for the purpose of constructing certain port
improvements located in Fernandino Beach, Nassau County, Florida. A letter of
credit was issued as security for the Adjustable Demand Revenue Bonds and was
guaranteed by the parent company of Nassau Terminals LLC, the operator of the
port facilities. In July 2002, we acquired Nassau Terminals LLC and became
guarantor under the letter of credit agreement. In December 2002, we issued a
$28 million letter of credit under our credit facilities and the former letter
of credit guarantee was terminated. Principal payments on the bonds are made on
the first of December each year and reductions are made to the letter of credit.
As of March 31, 2005, the value of this letter of credit outstanding under our
credit facility was $25.9 million.
Certain Relationships and Related Transactions
In conjunction with our acquisition of Natural Gas Pipelines assets from
KMI on December 31, 1999, December 31, 2000, and November 1, 2004, KMI became a
guarantor of approximately $733.5 million of our debt. KMI would be obligated to
perform under this guarantee only if we and/or our assets were unable to satisfy
our obligations.
For additional information regarding our debt facilities, see Note 9 to our
consolidated financial statements included in our Form 10-K for the year ended
December 31, 2004.
37
8. Partners' Capital
As of March 31, 2005 and December 31, 2004, our partners' capital consisted
of the following limited partner units:
March 31, December 31,
2005 2004
----------- ------------
Common units.................. 147,605,158 147,537,908
Class B units................. 5,313,400 5,313,400
i-units....................... 55,113,577 54,157,641
----------- ------------
Total limited partner units. 208,032,135 207,008,949
=========== ============
The total limited partner units represent our limited partners' interest and
an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights.
As of March 31, 2005, our common unit totals consisted of 133,249,423 units
held by third parties, 12,631,735 units held by KMI and its consolidated
affiliates (excluding our general partner), and 1,724,000 units held by our
general partner. As of December 31, 2004, our common unit total consisted of
133,182,173 units held by third parties, 12,631,735 units held by KMI and its
consolidated affiliates (excluding our general partner) and 1,724,000 units held
by our general partner.
On both March 31, 2005 and December 31, 2004, our Class B units were held
entirely by KMI and our i-units were held entirely by KMR. All of our Class B
units were issued to KMI in December 2000. The Class B units are similar to our
common units except that they are not eligible for trading on the New York Stock
Exchange.
Our i-units are a separate class of limited partner interests in us. All of
our i-units are owned by KMR and are not publicly traded. In accordance with its
limited liability company agreement, KMR's activities are restricted to being a
limited partner in us, and controlling and managing our business and affairs and
the business and affairs of our operating limited partnerships and their
subsidiaries. Through the combined effect of the provisions in our partnership
agreement and the provisions of KMR's limited liability company agreement, the
number of outstanding KMR shares and the number of i-units will at all times be
equal.
Furthermore, under the terms of our partnership agreement, we agreed that we
will not, except in liquidation, make a distribution on an i-unit other than in
additional i-units or a security that has in all material respects the same
rights and privileges as our i-units. The number of i-units we distribute to KMR
is based upon the amount of cash we distribute to the owners of our common
units. When cash is paid to the holders of our common units, we will issue
additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by
KMR will have a value based on the cash payment on the common unit.
The cash equivalent of distributions of i-units will be treated as if it had
actually been distributed for purposes of determining the distributions to our
general partner. We will not distribute the cash to the holders of our i-units
but will retain the cash for use in our business. If additional units are
distributed to the holders of our common units, we will issue an equivalent
amount of i-units to KMR based on the number of i-units it owns. Based on the
preceding, KMR received a distribution of 955,936 i-units on February 14, 2005.
These additional i-units distributed were based on the $0.74 per unit
distributed to our common unitholders on that date.
For the purposes of maintaining partner capital accounts, our partnership
agreement specifies that items of income and loss shall be allocated among the
partners, other than owners of i-units, in accordance with their percentage
interests. Normal allocations according to percentage interests are made,
however, only after giving effect to any priority income allocations in an
amount equal to the incentive distributions that are allocated 100% to our
general partner. Incentive distributions are generally defined as all cash
distributions paid to our general partner that are in excess of 2% of the
aggregate value of cash and i-units being distributed.
Incentive distributions allocated to our general partner are determined by
the amount quarterly distributions to unitholders exceed certain specified
target levels. Our distribution of $0.74 per unit paid on February 14, 2005 for
the fourth quarter of 2004 required an incentive distribution to our general
partner of $106.0 million. Our distribution of $0.68 per unit paid on February
13, 2004 for the fourth quarter of 2003 required an incentive
38
distribution to our general partner of $85.8 million. Our declared distribution
for the first quarter of 2005 of $0.76 per unit will result in an incentive
distribution to our general partner of approximately $111.1 million. This
compares to our distribution of $0.69 per unit and incentive distribution to our
general partner of approximately $90.7 million for the first quarter of 2004.
9. Comprehensive Income
SFAS No. 130, "Accounting for Comprehensive Income," requires that
enterprises report a total for comprehensive income. For the three months ended
March 31, 2005, the difference between our net income and our comprehensive
income resulted from unrealized gains or losses on derivatives utilized for
hedging purposes and from foreign currency translation adjustments. For the
three months ended March 31, 2004, the only difference between our net income
and our comprehensive income was the unrealized gain or loss on derivatives
utilized for hedging purposes. For more information on our hedging activities,
see Note 10. Our total comprehensive income is as follows (in thousands):
Three Months Ended March 31,
----------------------------
2005 2004
----------- ---------
Net income...................................... $ 223,621 $ 191,754
Foreign currency translation adjustments........ (227) -
Change in fair value of derivatives used
for hedging purposes........................... (556,835) (100,010)
Reclassification of change in fair value
of derivatives to net income................... 60,920 26,116
----------- ---------
Comprehensive income/(loss)................... $ (272,521) $ 117,860
=========== =========
10. Risk Management
Hedging Activities
Certain of our business activities expose us to risks associated with
changes in the market price of natural gas, natural gas liquids, crude oil and
carbon dioxide. We use energy financial instruments to reduce our risk of
changes in the prices of natural gas, natural gas liquids and crude oil markets
(and carbon dioxide to the extent contracts are tied to crude oil prices) as
discussed below. These risk management instruments are also called derivatives,
which are defined as financial instruments or contracts whose value is derived
from the worth and characteristics of some other financial measure called the
underlying, and includes payment provisions called the notional amount. The
value of a derivative (for example, options, swaps, futures contracts, etc.) is
a function of the underlying (for example, a specified interest rate, commodity
price, foreign exchange rate, or other variable) and the notional amount (for
example, payment in cash, commodities, or other units specified in a derivative
instrument), and while the underlying changes due to changes in market
conditions, the notional amount remains constant throughout the life of the
derivative contract.
Current accounting standards require derivatives to be reflected as assets
or liabilities at their fair market values and the fair value of our risk
management instruments reflects the estimated amounts that we would receive or
pay to terminate the contracts at the reporting date, thereby taking into
account the current unrealized gains or losses on open contracts. We have
available market quotes for substantially all of the financial instruments that
we use, including: commodity futures and options contracts, fixed-price swaps,
and basis swaps.
Pursuant to our management's approved policy, we are to engage in these
activities as a hedging mechanism against price volatility associated with:
- pre-existing or anticipated physical natural gas, natural gas liquids and
crude oil sales;
- pre-existing or anticipated physical carbon dioxide sales that have
pricing tied to crude oil prices;
- natural gas purchases; and
- system use and storage.
39
Our risk management activities are primarily used in order to protect our
profit margins and our risk management policies prohibit us from engaging in
speculative trading. Commodity-related activities of our risk management group
are monitored by our risk management committee, which is charged with the review
and enforcement of our management's risk management policy.
Specifically, our risk management committee is a separately designated
standing committee comprised of eleven executive-level employees of KMI or KMGP
Services Company, Inc. whose job responsibilities involve operations exposed to
commodity market risk and other external risks in the ordinary course of
business. Our risk management committee is chaired by our Chief Financial
Officer and is charged with the following three responsibilities:
- establish and review risk limits consistent with our risk tolerance
philosophy;
- recommend to the audit committee of our general partner's delegate any
changes, modifications, or amendments to our trading policy; and
- address and resolve any other high-level risk management issues.
Our derivatives hedge the commodity price risks derived from our normal
business activities, which include the sale of natural gas, natural gas liquids,
oil and carbon dioxide, and these derivatives have been designated by us as cash
flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that
hedge exposure to variable cash flows of forecasted transactions as cash flow
hedges and the effective portion of the derivative's gain or loss is initially
reported as a component of other comprehensive income (outside earnings) and
subsequently is reclassified into earnings when the forecasted transaction
affects earnings. If the transaction results in an asset or liability, amounts
in accumulated other comprehensive income should be reclassified into earnings
when the asset or liability affects earnings through cost of sales,
depreciation, interest expense, etc. To be considered effective, changes in the
value of the derivative or its resulting cash flows must substantially offset
changes in the value or cash flows of the item being hedged. The ineffective
portion of the gain or loss and any component excluded from the computation of
the effectiveness of the derivative instrument is reported in earnings
immediately.
The gains and losses included in "Accumulated other comprehensive loss" in
our accompanying consolidated balance sheets are reclassified into earnings as
the hedged sales and purchases take place. Approximately $345.6 million of the
Accumulated other comprehensive loss balance of $953.5 million representing
unrecognized net losses on derivative activities as of March 31, 2005 is
expected to be reclassified into earnings during the next twelve months.
During the three months ended March 31, 2005 and 2004, we reclassified $60.9
million and $26.1 million, respectively, of accumulated other comprehensive
income into earnings. The reclassification of accumulated other comprehensive
income into earnings during the three months ended March 31, 2005 reduced the
accumulated other comprehensive loss balance of $457.3 million, primarily
representing unrecognized net losses on derivative activities as of December 31,
2004. None of this reclassification into earnings during the first three months
of 2005, or any reclassification of accumulated other comprehensive income into
earnings during the first three months of 2004, resulted from the discontinuance
of cash flow hedges due to a determination that the forecasted transactions
would no longer occur by the end of the originally specified time period.
We recognized a loss of $0.2 million during the first quarter of 2005 as a
result of ineffective hedges, and we recognized no gain or loss during the first
quarter of 2004 as a result of ineffective hedges. All gains and losses
recognized as a result of ineffective hedges are reported within the captions
"Natural gas sales" and "Gas purchases and other costs of sales" in our
accompanying consolidated statements of income. For each of the three months
ended March 31, 2005 and 2004, we did not exclude any component of the
derivative instruments' gain or loss from the assessment of hedge effectiveness.
The differences between the current market value and the original physical
contracts value associated with our hedging activities are included within
"Other current assets", "Accrued other current liabilities", "Deferred charges
and other assets" and "Other long-term liabilities and deferred credits" in our
accompanying consolidated balance sheets. The following table summarizes the net
fair value of our energy financial instruments associated with our risk
management activities and included on our accompanying consolidated balance
sheets as of March 31, 2005 and
40
December 31, 2004 (in thousands):
March 31, December 31,
2005 2004
------------- -------------
Derivatives-net asset/(liability)
Other current assets...................... $ 91,037 $ 41,010
Deferred charges and other assets......... 50,471 17,408
Accrued other current liabilities......... (444,178) (218,967)
Other long-term liabilities and deferred
credits.................................. $ (666,867) $ (309,035)
As of March 31, 2005, we had two outstanding letters of credit totaling $248
million in support of our hedging activities.
Our over-the-counter swaps and options are with a number of parties, who
principally have investment grade credit ratings. We both owe money and are owed
money under these financial instruments; however, as of both March 31, 2005 and
December 31, 2004, we were essentially in a net payable position and had
virtually no amounts owed to us from other parties. In addition, defaults by
counterparties under over-the-counter swaps and options could expose us to
additional commodity price risks in the event that we are unable to enter into
replacement contracts for such swaps and options on substantially the same
terms. Alternatively, we may need to pay significant amounts to the new
counterparties to induce them to enter into replacement swaps and options on
substantially the same terms. While we enter into derivative transactions
principally with investment grade counterparties and actively monitor their
credit ratings, it is nevertheless possible that from time to time losses will
result from counterparty credit risk in the future.
Certain of our business activities expose us to foreign currency
fluctuations. However, due to the limited size of this exposure, we do not
believe the risks associated with changes in foreign currency will have a
material adverse effect on our business, financial position, results of
operations or cash flows.
Interest Rate Swaps
In order to maintain a cost effective capital structure, it is our policy to
borrow funds using a mix of fixed rate debt and variable rate debt. As of March
31, 2005 and December 31, 2004, we were a party to interest rate swap agreements
with notional principal amounts of $2.2 billion and $2.3 billion, respectively.
We entered into these agreements for the purpose of hedging the interest rate
risk associated with our fixed and variable rate debt obligations.
As of March 31, 2005, a notional principal amount of $2.1 billion of these
agreements effectively converts the interest expense associated with the
following series of our senior notes from fixed rates to variable rates based on
an interest rate of LIBOR plus a spread:
- $200 million principal amount of our 5.35% senior notes due August 15,
2007;
- $250 million principal amount of our 6.30% senior notes due February 1,
2009;
- $200 million principal amount of our 7.125% senior notes due March 15,
2012;
- $250 million principal amount of our 5.0% senior notes due December 15,
2013;
- $200 million principal amount of our 5.125% senior notes due November 15,
2014;
- $300 million principal amount of our 7.40% senior notes due March 15,
2031;
- $200 million principal amount of our 7.75% senior notes due March 15,
2032;
- $400 million principal amount of our 7.30% senior notes due August 15,
2033; and
- $100 million principal amount of our 5.80% senior notes due March 15,
2035.
41
These swap agreements have termination dates that correspond to the maturity
dates of the related series of senior notes, therefore, as of March 31, 2005,
the maximum length of time over which we have hedged a portion of our exposure
to the variability in the value of this debt due to interest rate risk is
through March 15, 2035. These interest rate swaps have been designated as fair
value hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives
that hedge a recognized asset or liability's exposure to changes in their fair
value as fair value hedges and the gain or loss on fair value hedges are to be
recognized in earnings in the period of change together with the offsetting loss
or gain on the hedged item attributable to the risk being hedged. The effect of
that accounting is to reflect in earnings the extent to which the hedge is not
effective in achieving offsetting changes in fair value.
The swap agreements related to our 7.40% senior notes contain mutual
cash-out provisions at the then-current economic value every seven years. The
swap agreements related to our 7.125% senior notes contain cash-out provisions
at the then-current economic value in March 2009. The swap agreements related to
our 7.75% senior notes and our 7.30% senior notes contain mutual cash-out
provisions at the then-current economic value every five or seven years.
As of both March 31, 2005 and December 31, 2004, we also had swap agreements
that effectively convert the interest expense associated with $100 million of
our variable rate debt to fixed rate debt. Half of these agreements, converting
$50 million of our variable rate debt to fixed rate debt, mature on August 1,
2005, and the remaining half mature on September 1, 2005. These swaps are
designated as a cash flow hedge of the risk associated with changes in the
designated benchmark interest rate (in this case, one-month LIBOR) related to
forecasted payments associated with interest on an aggregate of $100 million of
our portfolio of commercial paper.
Our interest rate swaps meet the conditions required to assume no
ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed for fair value hedges by SFAS No. 133.
Accordingly, we adjust the carrying value of each swap to its fair value each
quarter, with an offsetting entry to adjust the carrying value of the debt
securities whose fair value is being hedged. We record interest expense equal to
the variable rate payments or fixed rate payments under the swaps. Interest
expense is accrued monthly and paid semi-annually.
The differences between fair value and the original carrying value
associated with our interest rate swap agreements are included within "Deferred
charges and other assets" and "Other long-term liabilities and deferred credits"
in our accompanying consolidated balance sheets. The offsetting entry to adjust
the carrying value of the debt securities whose fair value was being hedged is
recognized as "Market value of interest rate swaps" on our accompanying
consolidated balance sheets.
The following table summarizes the net fair value of our interest rate swap
agreements associated with our interest rate risk management activities and
included on our accompanying consolidated balance sheets as of March 31, 2005
and December 31, 2004 (in thousands):
March 31, December 31,
2005 2004
--------------- -------------
Derivatives-net asset/(liability)
Deferred charges and other assets......... $ 89,981 $ 132,210
Other long-term liabilities and deferred
credits.................................. (12,825) (2,057)
--------- ---------
Market value of interest rate swaps..... $ 77,156 $ 130,153
========= =========
We are exposed to credit related losses in the event of nonperformance by
counterparties to these interest rate swap agreements. While we enter into
derivative transactions primarily with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that from
time to time losses will result from counterparty credit risk.
42
11. Reportable Segments
We divide our operations into four reportable business segments:
- Products Pipelines;
- Natural Gas Pipelines;
- CO2; and
- Terminals.
We evaluate performance principally based on each segments' earnings before
depreciation, depletion and amortization, which exclude general and
administrative expenses, third-party debt costs and interest expense,
unallocable interest income and minority interest. Our reportable segments are
strategic business units that offer different products and services. Each
segment is managed separately because each segment involves different products
and marketing strategies.
Our Products Pipelines segment derives its revenues primarily from the
transportation and terminaling of refined petroleum products, including
gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas
Pipelines segment derives its revenues primarily from the transmission, storage,
gathering and sale of natural gas. Our CO2 segment derives its revenues
primarily from the transportation and marketing of carbon dioxide used as a
flooding medium for recovering crude oil from mature oil fields and from the
production and sale of crude oil from fields in the Permian Basin of West Texas.
Our Terminals segment derives its revenues primarily from the transloading and
storing of refined petroleum products and dry and liquid bulk products,
including coal, petroleum coke, cement, alumina, salt, and chemicals.
Financial information by segment follows (in thousands):
Three Months Ended
March 31,
2005 2004
------------- -------------
Revenues
Products Pipelines............................ $ 171,283 $ 154,856
Natural Gas Pipelines......................... 1,472,892 1,437,908
CO2........................................... 163,163 105,586
Terminals..................................... 164,594 123,906
------------- -------------
Total consolidated revenues................... $ 1,971,932 $ 1,822,256
============= =============
Operating expenses(a)
Products Pipelines............................ $ 52,056 $ 42,878
Natural Gas Pipelines......................... 1,357,095 1,339,960
CO2........................................... 49,509 38,385
Terminals..................................... 85,416 60,106
------------- -------------
Total consolidated operating expenses......... $ 1,544,076 $ 1,481,329
============= =============
Depreciation, depletion and amortization
Products Pipelines............................ $ 19,394 $ 17,416
Natural Gas Pipelines......................... 14,758 12,842
CO2........................................... 38,702 26,988
Terminals..................................... 12,173 10,285
------------- -------------
Total consol. depreciation, depletion and
amortiz..................................... $ 85,027 $ 67,531
============= =============
Earnings from equity investments
Products Pipelines............................ $ 8,385 $ 5,019
Natural Gas Pipelines......................... 8,430 4,967
CO2........................................... 9,248 10,479
Terminals..................................... 9 4
------------- -------------
Total consolidated equity earnings............ $ 26,072 $ 20,469
============= =============
43
Three Months Ended
March 31,
2005 2004
------------- -------------
Amortization of excess cost of equity investments
Products Pipelines........................... $ 844 $ 821
Natural Gas Pipelines......................... 69 69
CO2........................................... 504 504
Terminals..................................... -- --
------------- -------------
Total consol. amortization of excess cost of
invests...................................... $ 1,417 $ 1,394
============= =============
Interest income
Products Pipelines............................. $ 1,149 $ --
Natural Gas Pipelines.......................... 171 --
CO2............................................ -- --
Terminals...................................... -- --
------------- -------------
Total segment interest income.................. 1,320 --
Unallocated interest income.................... 172 276
------------- -------------
Total consolidated interest income............. $ 1,492 $ 276
============= =============
Other, net-income (expense)
Products Pipelines............................ $ 142 $ (362)
Natural Gas Pipelines......................... (254) 1,130
CO2........................................... 1 9
Terminals..................................... (1,210) (34)
------------- -------------
Total consolidated Other, net-income (expense) $ (1,321) $ 743
============= =============
Income tax benefit (expense)
Products Pipelines............................. $ (3,301) $ (2,381)
Natural Gas Pipelines.......................... (457) (940)
CO2............................................ (45) 14
Terminals...................................... (3,772) (597)
------------- -------------
Total consolidated income tax benefit (expense) $ (7,575) $ (3,904)
============= =============
Segment earnings
Products Pipelines............................. $ 105,364 $ 96,017
Natural Gas Pipelines.......................... 108,860 90,194
CO2............................................ 83,652 50,211
Terminals...................................... 62,032 52,888
------------- -------------
Total segment earnings(b)...................... 359,908 289,310
Interest and corporate administrative
expenses(c)................................... (136,287) (97,556)
------------- -------------
Total consolidated net income.................. $ 223,621 $ 191,754
============= =============
Segment earnings before depreciation, depletion,
amortization and amortization of excess cost of
equity investments(d)
Products Pipelines............................. $ 125,602 $ 114,254
Natural Gas Pipelines.......................... 123,687 103,105
CO2............................................ 122,858 77,703
Terminals...................................... 74,205 63,173
------------- -------------
Total segment earnings before DD&A............. 446,352 358,235
Consolidated depreciation and amortization..... (85,027) (67,531)
Consolidated amortization of excess cost of
invests....................................... (1,417) (1,394)
Interest and corporate administrative expenses. (136,287) (97,556)
------------- -------------
Total consolidated net income.................. $ 223,621 $ 191,754
============= =============
Capital expenditures
Products Pipelines........................... $ 41,070 $ 31,011
Natural Gas Pipelines........................ 9,659 17,822
CO2.......................................... 52,557 76,715
Terminals.................................... 40,522 24,170
------------- -------------
Total consolidated capital expenditures(e)... $ 143,808 $ 149,718
============= =============
44
March 31, December 31,
2005 2004
------------- -------------
Assets
Products Pipelines........................... $ 3,666,831 $ 3,651,657
Natural Gas Pipelines........................ 3,618,936 3,691,457
CO2.......................................... 1,635,712 1,527,810
Terminals.................................... 1,623,717 1,576,333
------------- -------------
Total segment assets......................... 10,545,196 10,447,257
Corporate assets(f).......................... 82,525 105,685
------------- -------------
Total consolidated assets.................... $ 10,627,721 $ 10,552,942
============= =============
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
(b) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses,
depreciation, depletion and amortization, and amortization of excess cost
of equity investments.
(c) Includes unallocated interest income, interest and debt expense, general
and administrative expenses and minority interest expense.
(d) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses.
(e) Includes sustaining capital expenditures of $24,209 and $20,155 for the
three months ended March 31, 2005 and 2004, respectively. Sustaining
capital expenditures are defined as capital expenditures which do not
increase the capacity of an asset.
(f) Includes cash, cash equivalents and certain unallocable deferred charges.
We do not attribute interest and debt expense to any of our reportable
business segments. For the three months ended March 31, 2005 and 2004, we
reported (in thousands) total consolidated interest expense of $60,219 and
$47,497, respectively.
12. Pensions and Other Post-retirement Benefits
In connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk
Terminals, Inc. in 1998, we acquired certain liabilities for pension and
post-retirement benefits. We provide medical and life insurance benefits to
current employees, their covered dependents and beneficiaries of SFPP and Kinder
Morgan Bulk Terminals. We also provide the same benefits to former salaried
employees of SFPP. Additionally, we will continue to fund these costs for those
employees currently in the plan during their retirement years. SFPP's
post-retirement benefit plan is frozen and no additional participants may join
the plan.
The noncontributory defined benefit pension plan covering the former
employees of Kinder Morgan Bulk Terminals is the Kinder Morgan, Inc. Retirement
Plan. The benefits under this plan are based primarily upon years of service and
final average pensionable earnings; however, benefit accruals were frozen as of
December 31, 1998.
Net periodic benefit costs for these plans include the following components
(in thousands):
Other Post-retirement Benefits
------------------------------
Three Months Ended March 31,
------------------------------
2005 2004
----------- ---------
Net periodic benefit cost
Service cost...................... $ 2 $ 28
Interest cost..................... 77 97
Expected return on plan assets.... -- --
Amortization of prior service cost (29) (31)
Actuarial gain.................... (127) (244)
------ ------
Net periodic benefit cost......... $ (77) $ (150)
====== ======
45
Our net periodic benefit cost for the first quarter of 2005 was a credit of
$77,000, which resulted in increases to income, largely due to amortizations of
an actuarial gain and a negative prior service cost, primarily related to the
following:
- there have been changes to the plan for both 2004 and 2005 which reduced
liabilities, creating a negative prior service cost that is being
amortized each year; and
- there was a significant drop in 2004 in the number of retired
participants reported as pipeline retirees by Burlington Northern Santa
Fe, which holds a 0.5% special limited partner interest in SFPP, L.P.
As of March 31, 2005, we estimate our overall net periodic post-retirement
benefit cost for the year 2005 will be an annual credit of approximately $0.3
million. This amount could change in the remaining months of 2005 if there is a
significant event, such as a plan amendment or a plan curtailment, which would
require a remeasurement of liabilities.
13. Related Party Transactions
Plantation Pipe Line Company
We own a 51.17% equity interest in Plantation Pipe Line Company. An
affiliate of ExxonMobil owns the remaining 48.83% interest. In July 2004,
Plantation repaid a $10 million note outstanding and $175 million in outstanding
commercial paper borrowings with funds of $190 million borrowed from its owners.
We loaned Plantation $97.2 million, which corresponds to our 51.17% ownership
interest, in exchange for a seven year note receivable bearing interest at the
rate of 4.72% per annum. As of both December 31, 2004 and March 31, 2005, the
principal amount receivable from this note was $96.3 million. We have included
$2.2 million of this balance within "Accounts, notes and interest
receivable-Related Parties" on our consolidated balance sheets. The remaining
$94.1 million receivable is included within "Notes receivable-Related Parties"
on our consolidated balance sheets.
Coyote Gas Treating, LLC
We own a 50% equity interest in Coyote Gas Treating, LLC, referred to in
this report as Coyote Gulch. Coyote Gulch is a joint venture, and Enterprise
Field Services LLC owns the remaining 50% equity interest. We are the managing
partner of Coyote Gulch. In June 2001, Coyote repaid the $34.2 million in
outstanding borrowings under its 364-day credit facility with funds borrowed
from its owners. We loaned Coyote $17.1 million, which corresponds to our 50%
ownership interest, in exchange for a one-year note receivable bearing interest
payable monthly at LIBOR plus a margin of 0.875%. On June 30, 2002 and June 30,
2003, the note was extended for one year. On June 30, 2004, the term of the note
was made month-to-month. As of both December 31, 2004 and March 31, 2005, we
included the principal amount of $17.1 million related to this note within
"Notes Receivable-Related Parties" on our consolidated balance sheets.
Red Cedar Gas Gathering Company
We own a 49% equity interest in the Red Cedar Gas Gathering Company. Red
Cedar is a joint venture and the Southern Ute Indian Tribe owns the remaining
51% equity interest. On December 22, 2004, we entered into a $10 million
unsecured revolving credit facility due July 1, 2005, with the Southern Ute
Indian Tribe and us, as lenders, and Red Cedar, as borrower. Subject to the
terms of the agreement, the lenders may severally, but not jointly, make
advances to Red Cedar up to a maximum outstanding principal amount of $10
million. However, as of April 1, 2005, through July 1, 2005, the maximum
outstanding principal amount will be automatically reduced to $5 million. In
January 2005, Red Cedar borrowed funds of $4 million from its owners pursuant to
this credit agreement, and we loaned Red Cedar approximately $2.0 million, which
corresponds to our 49% ownership interest. The interest on all advances made
under this credit facility were calculated as simple interest on the combined
outstanding balance of the credit agreement at 6% per annum based upon a 360 day
year. In March 2005, Red Cedar paid the $4 million outstanding balance under
this revolving credit facility.
46
14. Recent Accounting Pronouncements
SFAS No. 123R
In December 2004, the FASB issued SFAS No. 123R (revised 2004),
"Share-Based Payment." This Statement amends SFAS No. 123, "Accounting for
Stock-Based Compensation," and requires companies to expense the value of
employee stock options and similar awards. Significant provisions of SFAS No.
123R include the following:
- share-based payment awards result in a cost that will be measured at fair
value on the awards' grant date, based on the estimated number of awards
that are expected to vest. Compensation cost for awards that vest would
not be reversed if the awards expire without being exercised;
- when measuring fair value, companies can choose an option-pricing model
that appropriately reflects their specific circumstances and the
economics of their transactions;
- companies will recognize compensation cost for share-based payment awards
as they vest, including the related tax effects. Upon settlement of
share-based payment awards, the tax effects will be recognized in the
income statement or additional paid-in capital; and
- public companies are allowed to select from three alternative transition
methods - each having different reporting implications.
In April 2005, the FASB decided to delay the effective date for public
companies to implement SFAS No. 123R (revised 2004). The new Statement is now
effective for public companies for annual periods beginning after June 15, 2005
(January 1, 2006, for us). We are currently reviewing the effects of this
accounting Statement; however, we have not granted common unit options since May
2000 and we do not expect the adoption of this Statement to have any immediate
effect on our consolidated financial statements.
FASB Staff Position Nos. FAS 109-1 and FAS 109-2
In December 2004, the FASB issued FASB Staff Position FAS 109-1,
"Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax
Deduction on Qualified Production Activities Provided by the American Jobs
Creation Act of 2004," which was effective upon issuance. This Staff Position
provides guidance on the application of FASB Statement No. 109, "Accounting for
Income Taxes," to the provision within the American Jobs Creation Act of 2004
that provides a tax deduction on qualified production activities. We do not
expect this Staff Position to have a material effect on our financial
statements.
In December 2004, the FASB issued FASB Staff Position FAS 109-2,
"Accounting and Disclosure Guidance for the Foreign Earnings Repatriation
Provision within the American Jobs Creation Act of 2004," which was effective
upon issuance. The American Jobs Creation Act of 2004 introduces a special
one-time dividends received deduction on the repatriation of certain foreign
earnings to a U.S. taxpayer ("repatriation provision"), provided certain
criteria are met. The Staff Position provides accounting and disclosure guidance
for the repatriation provision. We do not expect this Staff Position to have a
material effect on our financial statements.
FIN 47
In March 2005, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 47, "Accounting for Conditional Asset Retirement
Obligations--an interpretation of FASB Statement No. 143". This interpretation
clarifies that the term "conditional asset retirement obligation" as used in
SFAS No. 143, "Accounting for Asset Retirement Obligations," refers to a legal
obligation to perform an asset retirement activity in which the timing and (or)
method of settlement are conditional on a future event that may or may not be
within the control of the entity. The obligation to perform the asset retirement
activity is unconditional even though uncertainty exists about the timing and
(or) method of settlement. Thus, the timing and (or) method of settlement may be
conditional on a future event.
Accordingly, an entity is required to recognize a liability for the fair
value of a conditional asset retirement obligation if the fair value of the
liability can be reasonably estimated. The fair value of a liability for the
conditional asset retirement obligation should be recognized when
incurred-generally upon acquisition, construction, or development and (or)
through the normal operation of the asset. Uncertainty about the timing and (or)
method of settlement of a conditional asset retirement obligation should be
factored into the measurement of the liability when sufficient information
exists. FIN 47 also clarifies when an entity would have sufficient information
to reasonably estimate the fair value of an asset retirement obligation.
This Interpretation is effective no later than the end of fiscal years
ending after December 15 2005 (December 31, 2005, for us). We are currently
reviewing the effects of this Interpretation.
15. Subsequent Events
TGS Bulk Terminals
Effective April 29, 2005, we acquired seven bulk terminal operations from
Trans-Global Solutions, Inc. for an
47
aggregate consideration of approximately $245 million, consisting of $183.7
million in cash, $46.3 million in common units, and an obligation to pay an
additional $15 million on April 29, 2007. We will settle the $15 million
liability due two years from closing by issuing additional common units. All of
the acquired assets are located in the State of Texas, and include facilities at
the Port of Houston, the Port of Beaumont and the TGS Deepwater Terminal located
on the Houston Ship Channel. Certain of the terminals have contracts in place to
provide petroleum coke handling services for major Texas oil refineries. The
acquisition enlarges our Gulf Coast terminal region and expands our pre-existing
petroleum coke handling operations. We will include the acquired operations in
our Terminals business segment.
Environmental Settlements
In April 2005, we were informed by the office of the Attorney General of
California that the office was contemplating filing criminal charges against us
claiming discharge of diesel fuel arising from the April 2004 rupture from a
section of our Pacific operations' 14-inch Concord to Sacramento, California
products pipeline, and the failure to make timely notice of the discharge to
appropriate state agencies. For additional information on this issue, see Note 3
"Litigation and Other Contingencies--Environmental Matters--Cordelia,
California". In addition, we were told that the California Attorney General was
also contemplating filing charges alleging other releases and failures to
provide timely notice regarding certain environmental incidents at certain of
our facilities in California.
On April 26, 2005, we announced that we had entered into an agreement with
the Attorney General of the State of California and the District Attorney of
Solano County, California, to settle misdemeanor charges of the unintentional,
non-negligent discharge of diesel fuel resulting from this release and the
failure to provide timely notice of a threatened discharge to appropriate state
agencies as well as other potential claims in California regarding alleged
notice and discharge incidents. In addition to the charges settled by this
agreement, we entered into an agreement in principle to settle similar
additional misdemeanor charges in Los Angeles County, California, in connection
with the unintentional, non-negligent release of approximately five gallons of
diesel fuel at our Carson refined petroleum products terminal in Los Angeles
Harbor in May 2004.
Under the settlement agreement related to the Cordelia, California incident,
SFPP, L.P. agreed to plead guilty to four misdemeanors and to pay approximately
$5.2 million in fines, penalties, restitution, environmental improvement project
funding, and enforcement training in the State of California, and agreed to be
placed on informal, unsupervised probation for a term of three years. Under the
settlement agreement related to the Carson terminal incident, we agreed to plead
guilty to two additional misdemeanors and to pay approximately $0.2 million in
fines and penalties. In addition, we are currently in negotiations with the
United States Environmental Protection Agency, the United States Fish & Wildlife
Service, the California Department of Fish & Game and the San Francisco Regional
Water Quality Control Board regarding potential civil penalties and natural
resource damages assessments. We included the combined $5.4 million as general
and administrative expense in March 2005, and we have made payments in the
amount of $0.3 million as of March 31, 2005. We expect to pay the remaining $5.1
million in the second quarter of 2005. Since the April 2004 release in the
Suisun Marsh area near Cordelia, California, we have cooperated fully with
federal and state agencies and have worked diligently to remediate the affected
areas. As of April 30, 2005, the remediation is substantially complete.
As of March 31, 2005, we had not yet reached a settlement agreement with
the Office of the Attorney General of the State of California and the probable
impact of the issue was indeterminable. Due to the fact that the events that
gave rise to the settlement payments described above took place prior to March
31, 2005, we have included the effects of these settlement agreements in the
accompanying financial statements as required by generally accepted accounting
principles, resulting in general and administrative expenses of $73.9 million,
minority interest of $2.4 million, net income of $223.6 million, and basic and
diluted limited partners' net income per unit of $0.54, respectively, for the
quarter ended March 31, 2005.
Management Changes
On May 4, 2005, we announced that C. Park Shaper, formerly our Chief
Financial Officer, had been promoted and named our President, remaining a member
of the Office of the Chairman, and that Steve Kean, formerly our President -
Texas Intrastate Pipelines, had been promoted and named our Executive Vice
President - Operations, becoming a member of the Office of the Chairman. In
addition, we announced, that Kim Allen, had been promoted and named our Chief
Financial Officer, retaining her role in charge of investor relations, and that
David Kinder, our Vice President - Corporate Development, would also assume the
role of Treasurer, formerly held by Ms. Allen. We also announced that (i) Deb
Macdonald, our President - Natural Gas Pipeline would resign from that position
effective October 2005; (ii) Scott Parker, President of KMI's Natural Gas
Pipeline Company of America ("NGPL") would be promoted effective October 2005 to
our President - Natural Gas Pipelines; (iii) David Devine would become President
of NGPL effective October 2005; and (iv) Tom Martin had been promoted to
President - Texas Intrastate Pipelines.
48
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
The following discussion and analysis of our financial condition and results
of operations provides you with a narrative on our financial results. It
contains a discussion and analysis of the results of operations for each segment
of our business, followed by a discussion and analysis of our financial
condition. The following discussion and analysis should be read in conjunction
with (i) our accompanying interim consolidated financial statements and related
notes (included elsewhere in this report and prepared in accordance with
accounting principles generally accepted in the United States of America), and
(ii) our consolidated financial statements, related notes and management's
discussion and analysis of financial condition and results of operations
included in our Annual Report on Form 10-K for the year ended December 31, 2004.
Critical Accounting Policies and Estimates
Certain amounts included in or affecting our consolidated financial
statements and related disclosures must be estimated, requiring us to make
certain assumptions with respect to values or conditions that cannot be known
with certainty at the time the financial statements are prepared. These
estimates and assumptions affect the amounts we report for assets and
liabilities and our disclosure of contingent assets and liabilities at the date
of our financial statements. We evaluate these estimates on an ongoing basis,
utilizing historical experience, consultation with experts and other methods we
consider reasonable in the particular circumstances. Nevertheless, actual
results may differ significantly from our estimates. Any effects on our
business, financial position or results of operations resulting from revisions
to these estimates are recorded in the period in which the facts that give rise
to the revision become known.
In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, the fair
values used to determine possible asset impairment charges, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. Further information about us
and information regarding our accounting policies and estimates that we
considered to be "critical" can be found in our Annual Report on Form 10-K for
the year ended December 31, 2004. There have not been any significant changes in
these policies and estimates during the first quarter of 2005.
Results of Operations
Three Months Ended March 31,
----------------------------
2005 2004
------------ -----------
(In thousands)
Earnings before depreciation, depletion and
amortization expense and amortization
of excess cost of equity investments
Products Pipelines......................................... $ 125,602 $ 114,254
Natural Gas Pipelines...................................... 123,687 103,105
CO2........................................................ 122,858 77,703
Terminals.................................................. 74,205 63,173
------------ -----------
Segment earnings before depreciation,
depletion and amortization expense
and amortization of excess cost of
equity investments(a)...................................... 446,352 358,235
Depreciation, depletion and amortization expense........... (85,027) (67,531)
Amortization of excess cost of equity investments.......... (1,417) (1,394)
Interest and corporate administrative expenses(b)(c)....... (136,287) (97,556)
------------ -----------
Net income(c)................................................ $ 223,621 $ 191,754
============ ===========
- -------
(a) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses.
(b) Includes unallocated interest income, interest and debt expense, general
and administrative expenses and minority interest expense.
(c) 2005 amounts include a $5,387 general and administrative expense addition
and a $80 minority interest reduction from the amounts previously reported
in our 2005 first quarter earnings press release issued on April 20, 2005
due to environmental settlement agreements made after March 31, 2005 and
our earnings press release date. For more information, see Note 15 to our
consolidated financial statements included elsewhere in this report.
49
Our consolidated net income for the first quarter of 2005 was $223.6 million
($0.54 per diluted unit), compared to $191.8 million ($0.52 per diluted unit) in
the first quarter of last year. We earned total revenues of $1,971.9 million and
$1,822.3 million, respectively, in the three month periods ended March 31, 2005
and 2004.
The period-to-period increases in our net income and diluted earnings per
unit were primarily due to:
- higher earnings from our oil and gas producing activities, resulting both
from higher industry price levels for crude oil and gasoline plant
products and higher crude oil and plant product production volumes;
- higher margins associated with the supply and sales of natural gas,
favorable cashouts of natural gas pipeline imbalances, and higher
earnings from our natural gas gathering equity investees; and
- incremental earnings attributable to internal expansion projects and
strategic acquisitions completed since the end of the first quarter of
2004.
Because our partnership agreement requires us to distribute 100% of our
available cash to our partners on a quarterly basis (available cash consists
primarily of all our cash receipts, less cash disbursements and changes in
reserves), we look at each period's earnings before all non-cash depreciation,
depletion and amortization expenses, including amortization of excess cost of
equity investments, as an important measure of our success in maximizing returns
to our partners. In the first quarter of 2005, all four of our reportable
business segments reported increases in earnings before depreciation, depletion
and amortization, compared to the first quarter of 2004, with the strongest
growth coming from our CO2 (carbon dioxide) and Natural Gas Pipelines business
segments.
We declared a record cash distribution of $0.76 per unit for the first
quarter of 2005 (an annualized rate of $3.04). This distribution is 10% higher
than the $0.69 per unit distribution we made for the first quarter of 2004. We
expect to declare cash distributions of at least $3.13 per unit for 2005;
however, no assurance can be given that we will be able to achieve this level of
distribution.
Products Pipelines
Three Months Ended March 31,
--------------------------------
2005 2004
------------ -----------
(In thousands, except operating statistics)
Revenues.................................................. $ 171,283 $ 154,856
Operating expenses(a)..................................... (52,056) (42,878)
Earnings from equity investments.......................... 8,385 5,019
Interest income and Other, net-income (expense)........... 1,291 (362)
Income taxes.............................................. (3,301) (2,381)
------------ -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments........................................... 125,602 114,254
Depreciation, depletion and amortization expense.......... (19,394) (17,416)
Amortization of excess cost of equity investments......... (844) (821)
------------ -----------
Segment earnings........................................ $ 105,364 $ 96,017
============ ===========
Gasoline (MMBbl).......................................... 108.9 109.4
Diesel fuel (MMBbl)....................................... 40.2 38.4
Jet fuel (MMBbl).......................................... 29.3 28.7
------------ -----------
Total refined product volumes (MMBbl)................... 178.4 176.5
Natural gas liquids (MMBbl)............................... 9.6 11.5
------------ -----------
Total delivery volumes (MMBbl)(b)....................... 188.0 188.0
============ ===========
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
Our Products Pipelines segment reported earnings before depreciation,
depletion and amortization of $125.6 million on revenues of $171.3 million in
the first quarter of 2005. This compares to earnings before depreciation,
depletion and amortization of $114.3 million on revenues of $154.9 million in
the first quarter of 2004.
50
The segment's overall $11.3 million (10%) increase in earnings before
depreciation, depletion and amortization in the first quarter of 2005 versus the
first quarter of 2004 included a $4.6 million (8%) increase from our Pacific
operations, a $3.0 million (64%) increase in equity earnings from our
approximate 51% ownership interest in Plantation Pipe Line Company, and a $5.5
million increase in earnings before depreciation, depletion and amortization
from our Southeast product terminal operations, including incremental earnings
of $3.4 million from terminals acquired in November 2004 and $1.8 million from
terminals acquired in March 2004.
The quarter-to-quarter increase in earnings before depreciation, depletion
and amortization from our Pacific operations was largely related to a $4.8
million (6%) increase in operating revenues, driven by both higher mainline
delivery revenues and higher product terminal revenues. The $3.0 million
increase in equity earnings from our investment in Plantation was due to higher
Plantation net income, due to higher pipeline delivery revenues in the first
quarter of 2005 and higher litigation settlement expenses incurred in the first
quarter of 2004, related to the resolution of a past environmental issue. The
incremental earnings before depreciation, depletion and amortization from the
Southeast terminal operations acquired since the first quarter of 2004 includes
the earnings from both the ownership interests in nine refined petroleum
products terminals that we acquired in November 2004 from Charter Terminal
Company and Charter-Triad Terminals, LLC, and the seven petroleum products
terminals that we acquired effective March 9, 2004 from Exxon Mobil Corporation.
The overall increase in segment earnings before depreciation, depletion and
amortization in the first quarter of 2005, compared to the same period of 2004,
was partly offset by a $1.1 million (16%) decrease in earnings before
depreciation, depletion and amortization from our North System. The decrease
reflects a $1.0 million (9%) drop in operating revenues, due to a 24% decrease
in throughput delivery volumes, mainly caused by lower propane demand due to
warmer winter weather in the Midwest during 2005, relative to 2004.
Revenues for the segment increased $16.4 million (11%) in the first three
months of 2005 compared to the first three months of 2004. In addition to
incremental revenues of $11.8 million attributable to the Southeast terminals
acquired in March and November 2004, other period-to-period increases in
revenues included a $4.8 million increase from our Pacific operations (referred
to above), and a $0.8 million (9%) increase from our Central Florida Pipeline
operations. Pacific's quarter-over-quarter increase in revenues was driven by a
$3.9 million (7%) increase in mainline delivery revenues, due to higher average
tariff rates, which now include the 2004 annual indexed interstate tariff
increase.
Our Pacific operations also benefited from higher terminal revenues and
higher intrastate pipeline tariffs that were implemented following the
completion of the expanded North Line between Concord and Sacramento,
California, in December 2004. In November 2004, we filed an application with the
California Public Utilities Commission requesting a $9 million increase in
existing intrastate rates to reflect the in-service date of our Pacific
operation's replacement and expansion of its Concord-to-Sacramento pipeline. The
requested rate increase, which automatically became effective as of December 22,
2004 pursuant to CPUC regulations, is being collected subject to refund, pending
resolution of protests to the application by certain shippers. The CPUC is
expected to resolve the matter by the fourth quarter of 2005.
The increase in revenues from Central Florida was mainly due to an 11%
increase in pipeline throughput volumes, with the strongest growth in gasoline
and jet fuel volumes. Combined, the segment benefited from a 1% increase in the
volume of refined products delivered during the first quarter of 2005 compared
to the first quarter of 2004. Highlights included strong diesel volumes across
the entire segment, up almost 5%, and jet fuel delivery volumes increased 2% due
to strong commercial volumes. Offsetting the segment's overall increase in
refined product delivery volumes was an almost 5% decrease in military
deliveries from our Pacific operations, due to lower military activity in the
first quarter of 2005 compared to the first quarter of 2004, and a slight
decrease in total gasoline delivery volumes, due to lower deliveries from our
Pacific operations as a result of poor weather conditions in January and
February 2005.
The segment's operating expenses increased $9.2 million (21%) in the first
quarter of 2005, compared to the first quarter of 2004. The overall increase in
operating expenses included incremental expenses of $6.6 million from the
Southeast terminals acquired since March 2004, and a $0.8 million (28%) increase
from our CALNEV Pipeline, largely due to higher maintenance expenses associated
with line wash-outs resulting from adverse weather in the
51
State of California in the first quarter of 2005. Other period-to-period
increases in segment operating expenses included a $0.6 million (18%) increase
from our 49.8% proportionate interest in the Cochin Pipeline, mainly due to
higher labor and outside services associated with health, safety and security
work, and a $0.5 million (11%) increase in operating expenses from our North
System, mainly due to higher storage expenses related to a new contract
agreement entered into in April 2004.
Earnings from equity investments for the segment consisted primarily of
earnings related to our approximate 51% ownership interest in Plantation Pipe
Line Company and our 50% ownership interest in Heartland Pipeline Company. Total
equity earnings for the first quarter of 2005 increased $3.4 million (67%) from
the first quarter of 2004. The quarter-to-quarter increase includes the $3.0
million increase from our investment in Plantation (discussed above), and a $0.4
million (138%) increase in equity earnings from our investment in Heartland,
primarily due to higher product gains realized in the first quarter of 2005.
The segment's $1.7 million increase in interest and other income items in
the first quarter of 2005 compared to the first quarter of 2004 was mainly due
to the recognition, in 2005, of $1.1 million of interest income on our long-term
note receivable from Plantation Pipe Line Company. In July 2004, we loaned $97.2
million to Plantation to allow it to pay all of its outstanding credit facility
and commercial paper borrowings. In exchange for this funding, we received a
seven year note receivable bearing interest at the rate of 4.72% per annum. For
more information on this note receivable, see Note 13 to our consolidated
financial statements included elsewhere in this report.
The segment's $0.9 million (39%) increase in income tax expenses in the
first quarter of 2005 versus the first quarter of 2004 was mainly due to higher
pre-tax earnings realized by Plantation in the first quarter of 2005. Non-cash
depreciation, depletion and amortization charges, including amortization of
excess cost of investments, increased $2.0 million (11%) in the first quarter of
2005, compared to the same period last year. The increase was primarily due to
incremental depreciation charges associated with our Pacific operations, related
to the capital spending we have made since the end of the first quarter of 2004,
and to incremental charges associated with the Southeast terminals acquired
since March 2004.
Natural Gas Pipelines
Three Months Ended March 31,
---------------------------------
2005 2004
------------- -------------
(In thousands, except operating statistics)
Revenues.................................................. $ 1,472,892 $ 1,437,908
Operating expenses(a)..................................... (1,357,095) (1,339,960)
Earnings from equity investments.......................... 8,430 4,967
Interest income and Other, net-income (expense)........... (83) 1,130
Income taxes.............................................. (457) (940)
------------- -------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity 123,687 103,105
investments.................................................
Depreciation, depletion and amortization expense.......... (14,758) (12,842)
Amortization of excess cost of equity investments......... (69) (69)
------------- -------------
Segment earnings........................................ $ 108,860 $ 90,194
============= =============
Natural gas transport volumes (Trillion Btus)(b).......... 338.0 329.2
============= =============
Natural gas sales volumes (Trillion Btus)(c).............. 226.6 245.1
============= =============
- ----------
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
(b) Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate
natural gas pipeline group, Trailblazer and TransColorado pipeline volumes.
TransColorado volumes are included for both periods (acquisition date
November 1, 2004).
(c) Represents Texas intrastate natural gas pipeline group.
Our Natural Gas Pipelines business segment reported earnings before
depreciation, depletion and amortization of $123.7 million on revenues of
$1,472.9 million in the first quarter of 2005. This compares to earnings before
52
depreciation, depletion and amortization of $103.1 million on revenues of
$1,437.9 million in the first quarter of 2004.
The segment's $20.6 million (20%) increase in earnings before depreciation,
depletion and amortization expenses in the first three months of 2005 compared
to the same period of 2004 was largely attributable to higher quarter-to-quarter
earnings from our Trailblazer Pipeline and our Texas intrastate natural gas
pipeline group, higher equity earnings from our 49% ownership interest in the
Red Cedar Gas Gathering Company, and incremental earnings from our TransColorado
Pipeline, a 300-mile interstate natural gas pipeline system that we acquired
from KMI effective November 1, 2004.
Trailblazer reported a $6.6 million (67%) increase in earnings before
depreciation, depletion and amortization in the three months ended March 31,
2005, when compared to the same prior year period. The increase was primarily
due to timing differences on the favorable settlements of natural gas pipeline
transportation imbalances generated over time from normal transmission. Pipeline
transportation imbalances are the difference between the volumes received by a
pipeline versus the net volumes delivered (or redelivered) by the pipeline. All
imbalances have an economic value and can create profits and losses for the
parties involved.
Our Texas intrastate natural gas pipeline group reported an increase in
earnings before depreciation, depletion and amortization of $3.1 million (6%) in
the first quarter of 2005, compared to the first quarter of 2004. The increase
was primarily due to improved performance in our natural gas purchases and sales
business and the contributions from our natural gas pipeline to the Austin,
Texas market, which was placed into service in July 2004.
The quarter-over-quarter earnings before depreciation, depletion and
amortization from our ownership interest in Red Cedar, which we account for
under the equity method of accounting, increased $3.6 million (102%), primarily
due to additional sales of excess fuel gas, the result of favorable reductions
in the amount of natural gas lost and used within the system during gathering
operations. The TransColorado Pipeline, which extends from the Western Slope of
Colorado to the Blanco natural gas hub in northwestern New Mexico, reported
earnings before depreciation, depletion and amortization of $8.6 million on
revenues of $9.8 million in the first quarter of 2005.
The segment's overall increase in earnings before depreciation, depletion
and amortization in the first quarter of 2005 compared to the first quarter of
2004 was partially offset by a $1.2 million (27%) decrease in earnings from our
Casper Douglas gas gathering system, almost entirely due to higher costs
associated with natural gas acquired for processing. The increase in costs was
due to overall higher natural gas prices since the end of March 2004.
The period-to-period increases in revenues and operating expenses were
primarily attributable to higher natural gas sales and higher natural gas
purchases from our Kinder Morgan Tejas and Kinder Morgan Texas Pipeline systems.
Both pipeline systems buy and sell significant volumes of natural gas, which is
also transported on their pipelines, and our objective is to match purchases and
sales, thus locking-in the equivalent of a transportation fee. Combined, the two
systems reported increases in natural gas sales revenues of $34.4 million (3%)
in the first quarter of 2005 compared to the first quarter of 2004. Although
period-to-period natural gas sales volumes decreased almost 8% in 2005, largely
due to lower daily spot sales, the overall increase in gas sales revenues was
due to an 11% increase in average natural gas sale prices (from $5.339 per
dekatherm in first quarter 2004 to $5.927 per dekatherm in first quarter 2005).
The decline in spot (short-term) sales volumes was primarily due to lower
margins (defined as the difference between the prices at which we buy short-term
gas in our supply areas and the prices at which we sell short-term gas in our
market areas, less the cost of fuel to transport) in the first quarter of 2005
compared to the first quarter of 2004.
On the expense side, Kinder Morgan Tejas and Kinder Morgan Texas Pipeline
together reported a combined increase in costs of sales of $26.9 million (2%) in
the first quarter of 2005 compared to the first quarter of 2004. The increase
was due to higher average costs of natural gas sold, partially offset by lower
volumes of gas purchased for sale. The average price of purchased gas rose 11%
(from $5.22 per dekatherm in first quarter 2004 to $5.79 per dekatherm in first
quarter 2005), and the volumes of gas purchased decreased 8%, matching the
quarter-to-quarter percentage changes in average natural gas sale prices and
natural gas sales volumes, respectively.
Earnings from equity investments for the first quarter of 2005 increased
$3.5 million (70%) in the first three months of 2005 compared to the same period
last year. The increase reflects the positive contributions from Red
53
Cedar, as discussed above. Non-cash depreciation, depletion and amortization
charges, including amortization of excess cost of investments, increased $1.9
million (15%) in the first quarter of 2005, compared to the same year-ago
period. The increase was largely due to incremental depreciation expense of $1.2
million on the recently acquired TransColorado Pipeline.
CO2
Three Months Ended March 31,
----------------------------------
2005 2004
------------- -------------
(In thousands, except operating statistics)
Revenues.................................................. $ 163,163 $ 105,586
Operating expenses(a)..................................... (49,509) (38,385)
Earnings from equity investments.......................... 9,248 10,479
Other, net-income (expense)............................... 1 9
Income taxes.............................................. (45) 14
------------- -------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments........................................... 122,858 77,703
Depreciation, depletion and amortization expense(b)....... (38,702) (26,988)
Amortization of excess cost of equity investments......... (504) (504)
------------- -------------
Segment earnings........................................ $ 83,652 $ 50,211
============= =============
Carbon dioxide volumes transported (Bcf)(c)............... 169.9 182.5
============= =============
SACROC oil production (MBbl/d)(d)......................... 33.8 26.1
============= =============
Yates oil production (MBbl/d)(d).......................... 24.1 17.8
============= =============
Natural gas liquids sales volumes (MBbl/d)(e)............. 9.7 6.7
============= =============
Realized weighted average oil price per Bbl(f)(g)......... $ 28.81 $ 25.37
============= =============
Realized weighted average natural gas liquids price per
Bbl(g)(h)............................................... $ 33.97 $ 26.68
============= =============
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) Includes expenses associated with oil and gas production activities and gas
processing activities in the amount of $34,197 for the first quarter of
2005 and $23,116 for the first quarter of 2004. Includes expenses
associated with sales and transportation services activities in the amount
of $4,505 for the first quarter of 2005 and $3,872 for the first quarter of
2004.
(c) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos
pipeline volumes. (d) Represents 100% of the production from the field. We
own an approximate 97% working interest in the SACROC
unit and an approximate 50% working interest in the Yates unit.
(e) Net to Kinder Morgan.
(f) Includes all Kinder Morgan crude oil production properties.
(g) Hedge gains/losses for oil and natural gas liquids are included with crude
oil.
(h) Includes production attributable to leasehold ownership and production
attributable to our ownership in processing plants and third party
processing agreements.
Our CO2 business segment reported earnings before depreciation, depletion
and amortization of $122.9 million on revenues of $163.2 million in the first
quarter of 2005. These amounts compare to earnings before depreciation,
depletion and amortization of $77.7 million on revenues of $105.6 million in the
same quarter last year.
The $45.2 million (58%) increase in segment earnings before depreciation,
depletion and amortization in the first quarter of 2005 over the first quarter
of 2004 was primarily driven by higher earnings from the segment's oil and gas
producing activities, which include the operations associated with our ownership
interests in oil-producing fields and gas processing plants. These operations
include all construction, drilling and production activities necessary to
produce oil and gas from its natural reservoirs, and all of the activities where
natural gas is processed to extract liquid hydrocarbons called natural gas
liquids. Our combined oil and gas producing activities reported earnings before
depreciation, depletion and amortization in the amount of $85.1 million for the
three months ended March 31, 2005, an increase of $40.0 million (89%) over
earnings before depreciation, depletion and amortization for the three months
ended March 31, 2004. The growth in earnings was primarily attributable to
higher revenues from the sale of crude oil and plant products, due to higher
weighted average prices realized from the sale of oil and natural gas liquids
products and to higher crude oil and plant product production volumes.
In the first quarter of 2005, we benefited from a 32% increase in combined
daily oil production volumes from the two largest oil field units in which we
hold ownership interests. These interests consist of our approximate 97%
54
working interest in the SACROC oil field unit and our approximate 50% working
interest in the Yates oil field unit. Both the SACROC and Yates oil field units
are located in the Permian Basin area of West Texas. We also benefited from
increases of 14% and 27%, respectively, in our realized weighted average price
of oil and natural gas liquids per barrel in the first quarter of 2005, versus
the first quarter of 2004.
The increase in crude oil and plant product prices since the end of the
first quarter of 2004, and the subsequent impact of increased production volumes
has largely been driven by increased product demand, attributable to many
factors, including higher economic growth, crude oil supply concerns, and the
heightened level of geopolitical uncertainty in many areas of the world.
Therefore, we are exposed to market risks related to price volatility of crude
oil, natural gas liquids and carbon dioxide (to the extent contracts are tied to
crude oil prices), and we use financial derivative commodity instruments to
manage this exposure on certain activities, including firm commitments and
anticipated transactions for the sale of crude oil, natural gas liquids and
carbon dioxide. We mitigate our commodity price risk through a long-term hedging
strategy that is intended to generate more stable realized prices. For more
information on our hedging activities, see Note 10 to our consolidated financial
statements, included elsewhere in this report.
Our CO2 segment's carbon dioxide sales and transportation activities
reported earnings before depreciation, depletion and amortization in the amount
of $37.8 million for the three months ended March 31, 2005, an increase of $5.2
million (16%) over earnings before depreciation, depletion and amortization for
the three months ended March 31, 2004. The increase was driven by higher
revenues from carbon dioxide sales and by incremental earnings from the Kinder
Morgan Wink Pipeline, a 450-mile crude oil pipeline system located in West Texas
and acquired effective August 31, 2004. For the first quarter of 2005, the Wink
Pipeline reported earnings before depreciation, depletion and amortization of
$4.6 million, revenues of $5.8 million and operating expenses of $1.2 million.
Additionally, we continue to invest and expand our CO2 asset infrastructure.
For the first three months of 2005, capital expenditures for our CO2 business
segment totaled $52.6 million, the highest for all four of our reportable
business segments. The expenditures largely represented incremental spending for
new well and injection compression facilities at the SACROC and Yates oil field
units in order to enhance oil recovery from carbon dioxide injection. For the
three months ended March 31, 2004, capital spending for our CO2 segment totaled
$76.7 million. Additionally, in the first quarter of 2005, we spent $6.2 million
to acquire an approximate 64.5% gross working interest in the Claytonville oil
field unit, also located in the Permian Basin.
The $57.6 million (55%) period-to-period increase in revenues was mainly due
to higher crude oil and plant product sales revenues, and higher revenues
from carbon dioxide sales and crude oil transportation service, as described
above. The increases were driven by higher average crude oil and plant product
prices, higher oil and plant product production volumes, higher average carbon
dioxide sale prices and the inclusion of the Wink Pipeline. The overall increase
in segment revenues was partly offset by lower carbon dioxide transportation
revenues, due to lower aggregate volumes transported. Combined deliveries of
carbon dioxide on our Central Basin Pipeline, our Centerline Pipeline, our
majority-owned Canyon Reef Carriers and Pecos Pipelines, and our 50% owned
Cortez Pipeline, which is accounted for under the equity method of accounting,
decreased 12.6 billion cubic feet (7%) in the first quarter of 2005 compared to
the first quarter of 2004. The decrease was largely due to lower deliveries of
carbon dioxide to the SACROC unit by the Centerline and Canyon Reef Carrier
pipelines during the first quarter of 2005, as the demand for additional
deliveries at SACROC fluctuates across periods and is not directly related to
changes in oil production.
The $11.1 million (29%) period-to-period increase in operating expenses
mainly related to higher property and production taxes, higher fuel and power
costs and higher operating and maintenance expenses, all as a result of the
quarter-to-quarter increase in oil production volumes and the increase in
capitalized assets since the end of the first quarter of 2004. The level of
operating expenses associated with the efficient production of oil and gas is
also affected by certain external factors, including the general level of
inflation and prices charged by the industry's service providers, which can be
affected by the volatility of the industry's own supply and demand conditions
for crude oil and natural gas.
The $1.2 million (12%) decrease in earnings from equity investments in the
first quarter of 2005 compared to the first quarter of 2004 was due to lower
earnings from our 50% investment in the Cortez Pipeline Company. The
55
decrease in equity earnings reflected lower net income earned by Cortez, mainly
due to lower revenues as a result of lower average tariff rates and a slight
drop in carbon dioxide delivery volumes in the first quarter of 2005 versus the
first quarter of 2004.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, were up $11.7 million (43%) in the
first three months of 2005 compared to the same period of 2004, primarily due to
higher oil production and corresponding higher unit-of-production depletion
rates.
Terminals
Three Months Ended March 31,
----------------------------------
2005 2004
------------- -------------
(In thousands, except operating statistics)
Revenues.................................................. $ 164,594 $ 123,906
Operating expenses(a)..................................... (85,416) (60,106)
Earnings from equity investments.......................... 9 4
Other, net-income (expense)............................... (1,210) (34)
Income taxes.............................................. (3,772) (597)
------------- -------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity 74,205 63,173
investments.................................................
Depreciation, depletion and amortization expense.......... (12,173) (10,285)
Amortization of excess cost of equity investments......... - -
------------- -------------
Segment earnings........................................ $ 62,032 $ 52,888
============= =============
Bulk transload tonnage (MMtons)(b)........................ 20.2 17.3
============= =============
Liquids leaseable capacity (MMBbl)........................ 36.6 36.1
============= =============
Liquids utilization %..................................... 96.7% 96.0%
============ ============
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs; excludes operatorship of LAXT bulk terminal. Volumes
for acquired terminals are included for both periods.
Our Terminals segment, including the operations of our dry-bulk material
terminals and our petroleum and petrochemical-related liquids terminal
facilities, reported earnings before depreciation, depletion and amortization of
$74.2 million on revenues of $164.6 million in the first quarter of 2005. This
compares to earnings before depreciation, depletion and amortization of $63.2
million on revenues of $123.9 million in the first quarter last year.
For all terminal operations owned during both quarters, earnings before
depreciation, depletion and amortization increased $4.3 million (7%) in the
first quarter of 2005 versus the first quarter of 2004. The increase was mainly
the result of a $2.0 million increase in earnings before depreciation, depletion
and amortization from our Gulf Coast terminals, which include two liquids
terminals located in Pasadena and Galena Park, Texas and which serve as a
distribution hub for Houston's crude oil refineries. The increase in earnings
before depreciation, depletion and amortization from our Gulf Coast terminals
was driven by record volumes of liquids throughput at the Houston Ship Channel
in the first quarter of 2005. For all of our liquids terminals combined, we
reported a 5% increase in throughput in the first quarter of 2005 compared to
the first quarter of 2004. We also reported a $1.5 million increase in earnings
before depreciation, depletion and amortization from our Mid-Atlantic terminals,
which include our Chesapeake Bay, Maryland bulk terminal and our Grand Rivers,
Kentucky coal terminal. The quarter-to-quarter increases at both facilities were
mainly due to higher operating revenues; the increase at Chesapeake was
primarily due to higher volumes of petroleum coke and other services related to
an increase in steel production at the International Steel Group Inc.'s Sparrows
Point, Maryland steel-making facility, and the increase at Grand Rivers was due
to a 28% increase in coal transfer volumes.
Key acquisitions of terminal businesses since the end of the first quarter
of 2004 accounted for $6.7 million of incremental earnings before depreciation,
depletion and amortization in the first quarter of 2005. These acquisitions
included:
56
- our North Charleston, South Carolina bulk terminal, acquired effective
April 30, 2004;
- the river terminals and rail transloading facilities operated by
Kinder Morgan River Terminals LLC and its consolidated subsidiaries,
acquired effective October 6, 2004; and
- our Kinder Morgan Fairless Hills terminal, the major port distribution
facility located along the Delaware River at the Fairless Industrial
Park in Bucks County, Pennsylvania, acquired effective December 1,
2004.
The above acquisitions reported revenues of $21.4 million and operating
expenses of $13.2 million in the first quarter of 2005.
Segment revenues for all terminals owned during both periods increased $19.3
million (16%) in the first quarter of 2005 compared to the first quarter of
2004. Most of the increase related to higher bulk tonnage transfer volumes,
higher liquids storage and throughput volumes, higher dockage and ship
conveyance fees, and higher revenues from drumming and other in-plant services.
Terminal specific quarter-over-quarter increases in revenues included the
following:
- a $3.8 million increase at our Chesapeake Bay facility, primarily due
to higher volumes of petroleum coke, ore and steel coils, and higher
in-plant services;
- a $2.9 million increase at our Pasadena liquids terminal, primarily
due to higher transmix sales, higher throughput volumes and additional
customer contracts;
- a $2.0 million increase at our Longview, Washington bulk terminal,
primarily due to higher volumes of soda ash;
- a $1.4 million increase at the International Marine Terminal
Partnership (owned 66 2/3% by us), primarily due to higher tonnage and
higher dockage revenues; and
- a $1.2 million increase at our liquids terminal located in Harvey,
Louisiana, primarily due to additional liquids volumes and higher
drumming revenues.
Operating expenses for all terminals owned during both periods increased
$12.1 million (20%) in the first quarter of 2005 versus the first quarter of
2004. The increase was mainly due to higher operating, maintenance, and fuel and
power expenses associated with higher volumes of liquids and bulk tonnage.
Other income items decreased $1.2 million in the first quarter of 2005
versus the first quarter of 2004. The decrease related to a disposal loss in the
first quarter of 2005 on warehouse property at our Elizabeth River bulk
terminal, located in Chesapeake, Virginia. Income tax expenses for the first
quarter of 2005 increased $3.2 million over the comparable period last year.
Approximately half of the increase was due to higher taxable income from Kinder
Morgan Bulk Terminals, Inc., the tax-paying entity that owns many of our bulk
terminal businesses. The remaining increase was incremental tax expense related
to the taxable income of Kinder Morgan River Terminals LLC and its consolidated
subsidiaries, acquired effective October 6, 2004.
Non-cash depreciation, depletion and amortization charges increased $1.9
million (18%) in the first quarter of 2005, compared to last year's first
quarter. In addition to increases associated with normal capital spending, the
increase reflects higher depreciation charges due to the terminal acquisitions
we have made since the end of the first quarter of 2004.
57
Other
Three Months Ended March 31,
----------------------------------
2005 2004
------------- -------------
(In thousands-income/(expense))
General and administrative expenses.................. $ (73,852) $ (48,254)
Unallocable interest, net............................ (60,047) (47,221)
Minority interest.................................... (2,388) (2,081)
------------- -------------
Interest and corporate administrative expenses..... $ (136,287) $ (97,556)
============= =============
Items not attributable to any segment include general and administrative
expenses, unallocable interest income, interest expense and minority interest.
Our general and administrative expenses, which include such items as salaries
and employee-related expenses, payroll taxes, legal fees, unallocated litigation
and environmental settlements, insurance, and office supplies and rentals,
increased $25.6 million (53%) in the first quarter of 2005, when compared to the
same period last year. The increase was largely due to incremental expenses of
$30.4 million in the first quarter of 2005 related to unallocated litigation and
environmental settlements, consisting of a $25 million expense for a settlement
reached between us and a shipper on our Kinder Morgan Tejas natural gas pipeline
system, and a $5.4 million expense related to settlements of environmental
matters at certain of our operating sites located in the State of California.
For more information on these environmental matters, see Notes 3 and 15 to our
consolidated financial statements, included elsewhere in this report. Partially
offsetting the overall increase in general and administrative expenses was a
reduction in expense in the amount of $3.0 million related to proceeds received
in the first quarter of 2005 in connection with the settlement of claims in the
Enron Corp. bankruptcy proceeding.
Unallocable interest expense, net of interest income, increased $12.8
million (27%) in the first quarter of 2005, versus the same year-earlier period.
We incurred higher interest charges as a result of an almost 13% increase in
average borrowings during the three month period ended March 31, 2005, compared
to the same three month period in 2004. The increase in average borrowings was
primarily due to both capital spending related to internal expansions and
improvements, and to incremental borrowings associated with acquisition
expenditures made since the end of the first quarter of 2004. In addition, a
general rise in interest rates since the end of the first quarter of 2004
resulted in a higher average borrowing rate on all of our outstanding debt
during the first quarter of 2005, compared to the first quarter of 2004. The
weighted average interest rate on all of our borrowings was approximately 4.901%
during the first quarter of 2005 and 4.385% during the first quarter of 2004.
Minority interest, representing the deduction in our consolidated net income
attributable to all outstanding ownership interests in our five operating
limited partnerships and their consolidated subsidiaries that are not held by
us, increased $0.3 million (15%) in the first quarter of 2005, versus the first
quarter of 2004. The increase was primarily due to higher overall partnership
income, resulting in higher income allocable to Kinder Morgan G.P., Inc., our
general partner and holder of a 1.0101% general partner interest in each of our
operating partnerships.
Financial Condition
We attempt to maintain a conservative overall capital structure, with a
long-term target mix of approximately 60% equity and 40% debt. The following
table illustrates the sources of our invested capital (dollars in thousands). In
addition to our results of operations, these balances are affected by our
financing activities as discussed below:
March 31, December 31,
------------ ------------
2005 2004
------------ ------------
Long-term debt, excluding market value of interest rate swaps.. $ 4,867,521 $4,722,410
Minority interest.............................................. 40,619 45,646
Partners' capital, excluding accumulated other comprehensive
loss.......................................................... 4,358,139 4,353,863
------------ ------------
Total capitalization......................................... 9,266,279 9,121,919
Short-term debt, less cash and cash equivalents................ - -
------------ ------------
Total invested capital....................................... $ 9,266,279 $ 9,121,919
============ ============
58
March 31 December 31
------------ ------------
2005 2004
------------ ------------
Capitalization:
Long-term debt, excluding market value of interest rate swaps 52.5% 51.8%
Minority interest............................................ 0.5% 0.5%
Partners' capital, excluding accumulated other comprehensive
loss....................................................... 47.0% 47.7%
------------ ------------
100.0% 100.0%
============ ============
Invested Capital:
Total debt, less cash and cash equivalents and excluding
market value of interest rate swaps..................... 52.5% 51.8%
Partners' capital and minority interest, excluding accumulated
other comprehensive loss ............................... 47.5% 48.2%
------------ ------------
100.0% 100.0%
============ ============
Our primary cash requirements, in addition to normal operating expenses, are
debt service, sustaining capital expenditures, expansion capital expenditures
and quarterly distributions to our common unitholders, Class B unitholders and
general partner. In addition to utilizing cash generated from operations, we
could meet our cash requirements (other than distributions to our common
unitholders, Class B unitholders and general partner) through borrowings under
our credit facility, issuing short-term commercial paper, long-term notes or
additional common units or issuing additional i-units to KMR. In general, we
expect to fund:
- cash distributions and sustaining capital expenditures with existing cash
and cash flows from operating activities;
- expansion capital expenditures and working capital deficits with retained
cash (resulting from including i-units in the determination of cash
distributions per unit but paying quarterly distributions on i-units in
additional i-units rather than cash), additional borrowings, the issuance
of additional common units or the issuance of additional i-units to KMR;
- interest payments with cash flows from operating activities; and
- debt principal payments with additional borrowings, as such debt
principal payments become due, or by the issuance of additional common
units or the issuance of additional i-units to KMR.
As a publicly traded limited partnership, our common units are attractive
primarily to individual investors, although such investors represent a small
segment of the total equity capital market. We believe that some institutional
investors prefer shares of KMR over our common units due to tax and other
regulatory considerations. We are able to access this segment of the capital
market through KMR's purchases of i-units issued by us with the proceeds from
the sale of KMR shares to institutional investors.
As of March 31, 2005, our forecasted expenditures for the remaining nine
months of 2005 for sustaining capital spending were approximately $105.5
million, based on our 2005 sustaining capital expenditure forecast. This amount
has been committed primarily for the purchase of plant and equipment. Sustaining
capital expenditures are defined as capital expenditures which do not increase
the capacity of an asset. All of our capital expenditures, with the exception of
sustaining capital expenditures, are discretionary.
In addition, some of our customers are experiencing, or may experience in
the future, severe financial problems that have had a significant impact on
their creditworthiness. We are working to implement, to the extent allowable
under applicable contracts, tariffs and regulations, prepayments and other
security requirements, such as letters of credit, to enhance our credit position
relating to amounts owed from these customers. We cannot provide assurance that
one or more of our financially distressed customers will not default on their
obligations to us or that such a default or defaults will not have a material
adverse effect on our business, financial position, future results of operations
or future cash flows.
59
Operating Activities
Net cash provided by operating activities was $259.5 million for the three
months ended March 31, 2005, versus $270.1 million in the comparable period of
2004. The quarter-to-quarter decrease of $10.6 million (4%) in cash flow from
operations consisted of:
- a $76.6 million increase in cash from overall higher partnership
income, net of non-cash items including depreciation charges and
undistributed earnings from equity investments;
- a $71.2 million decrease in cash inflows relative to net changes in
working capital items;
- a $10.2 million decrease in cash inflows relative to net changes in
non-current assets and liabilities; and
- a $5.8 million decrease related to lower distributions received from
equity investments.
The higher partnership income reflects the record level of segment earnings
before depreciation, depletion and amortization reported in the first three
months of 2005 and discussed above in "Results of Operations." The decrease in
cash from working capital in the first quarter of 2005 compared to the first
quarter of 2004 was mainly related to timing differences that resulted in higher
payments in 2005 on trade accounts payables and lower collections on short-term
natural gas pipeline imbalance receivables. The decrease in cash inflows
relative to net changes in non-current items related to, among other things,
higher payments made in the first quarter of 2005 to reduce both long-term
natural gas imbalance liabilities and long-term reserves for natural gas lost
and used during transmission. Finally, the decrease in cash from lower
distributions received from equity investees was primarily due to lower
distributions received from Red Cedar in the first quarter of 2005 compared to
the first quarter of 2004. Since the summer of 2004, Red Cedar has increased its
expansion capital spending and has funded a large portion of the expenditures
with retained cash.
Investing Activities
Net cash used in investing activities was $168.0 million for the three month
period ended March 31, 2005, compared to $196.6 million in the comparable 2004
period. The $28.6 million (15%) decrease in cash used in investing activities
was primarily attributable to lower expenditures made in the first three months
of 2005 for both strategic acquisitions and capital additions to our existing
asset infrastructure.
For the first quarter of 2005, our acquisition outlays totaled $6.5 million,
which primarily related to our acquisition of a 64.5% gross working interest in
the Claytonville oil field unit located in West Texas. For the comparable
quarter last year, our acquisition outlays totaled $50.3 million, including
$48.1 million for the acquisition of seven refined petroleum products terminals
in the southeastern United States from Exxon Mobil Corporation. Including
expansion and maintenance projects, our capital expenditures were $143.8 million
in the first three months of 2005 versus $149.7 million in the same year-ago
period. The $5.9 million (4%) decrease was chiefly due to lower capital
investment in our CO2 business segment during the first quarter of 2005, versus
the first quarter of 2004. We plan to invest approximately $240 million this
year to further increase oil production at both the SACROC and Yates oil field
units.
Our sustaining capital expenditures were $24.2 million for the first three
months of 2005 compared to $20.2 million for the first three months of 2004.
Partially offsetting the overall decrease in cash used in investing activities
was an $18.1 million use of cash in the first quarter of 2005 related to an
increase in margin deposits associated with hedging activities utilizing
energy derivative instruments. For more information on our hedging activities,
see Note 10 to our consolidated financial statements included elsewhere in this
report.
Financing Activities
Net cash used in financing activities amounted to $91.5 million for the
three months ended March 31, 2005 and $50.0 million for the same prior-year
period. The $41.5 million quarter-to-quarter increase in cash used in financing
activities resulted primarily from a $251.8 million increase due to lower cash
proceeds from partnership equity issuances, a $38.8 million increase due to
higher partnership distributions, and an $8.6 million increase due to a
reduction in our temporary cash book overdrafts, which represent outstanding
checks in excess of funds on deposit. The overall increase in cash used in
financing activities was partially offset by a $259.5 million increase in cash
inflows from overall debt financing activities, which include both issuances and
payments of debt, and debt issuance
60
costs.
The period-to-period decrease in cash flows from partnership equity
issuances primarily relates to the cash received from our February 2004 issuance
of common units and our March 2004 issuance of i-units. On February 9, 2004, we
issued, in a public offering, an additional 5,300,000 of our common units at a
price of $46.80 per unit, less commissions and underwriting expenses. After
these fees, we received net proceeds of $237.8 million for the issuance of these
common units. On March 25, 2004, we issued an additional 360,664 of our i-units
to KMR at a price of $41.59 per share, less closing fees and commissions. After
fees, we received net proceeds of $14.9 million for the issuance of these
i-units. We used the proceeds from each of these issuances to reduce the
borrowings under our commercial paper program. The $1.2 million in cash received
during the first quarter of 2005 from the issuance of common units represented
proceeds we received upon the exercise of common unit options by employees of
KMI or KMGP Services Company, Inc. pursuant to our common unit option plan.
Distributions to partners, consisting of our common and Class B unitholders,
our general partner and minority interests, totaled $223.5 million in the first
quarter of 2005 compared to $184.7 million in the same year-earlier period. The
increase in distributions was due to an increase in the per unit cash
distributions paid, an increase in the number of units outstanding and an
increase in our general partner incentive distributions. The increase in our
general partner incentive distributions resulted from both increased cash
distributions per unit and an increase in the number of common units and i-units
outstanding.
The $259.5 million increase in cash inflows from overall debt financing
activities was primarily due to the following:
- a $498.7 million increase from the issuance of senior notes. On March 15,
2005, we closed a public offering of $500 million in principal amount of
5.80% senior notes due March 15, 2035. We used the proceeds from this
issuance to reduce the borrowings under our commercial paper program;
- a $200 million decrease from the retirement of senior notes. On March 15,
2005, we paid a maturing amount of $200 million in principal amount of
8.0% senior notes due on that date;
- a $34.7 million decrease due to higher net payments on commercial paper
borrowings in the first quarter of 2005 versus the first quarter of 2004;
and
- a $4.2 million decrease due to higher debt issuance costs, largely
attributable to our March 2005 issuance of senior notes.
Partnership Distributions
Our partnership agreement requires that we distribute 100% of "Available
Cash," as defined in our partnership agreement, to our partners within 45 days
following the end of each calendar quarter in accordance with their respective
percentage interests. Available Cash consists generally of all of our cash
receipts, including cash received by our operating partnerships and net
reductions in reserves, less cash disbursements and net additions to reserves
and amounts payable to the former general partner of SFPP, L.P. in respect of
its remaining 0.5% interest in SFPP.
Our general partner is granted discretion by our partnership agreement,
which discretion has been delegated to KMR, subject to the approval of our
general partner in certain cases, to establish, maintain and adjust reserves for
future operating expenses, debt service, maintenance capital expenditures, rate
refunds and distributions for the next four quarters. These reserves are not
restricted by magnitude, but only by type of future cash requirements with which
they can be associated. When KMR determines our quarterly distributions, it
considers current and expected reserve needs along with current and expected
cash flows to identify the appropriate sustainable distribution level. For 2004,
2003 and 2002, we distributed 87.0%, 100.4% and 97.6%, of the total of cash
receipts less cash disbursements, respectively (calculations assume that KMR
unitholders received cash). The difference between these numbers and 100% of
distributable cash flow reflects net changes in reserves.
61
Our general partner and owners of our common units and Class B units receive
distributions in cash, while KMR, the sole owner of our i-units, receives
distributions in additional i-units. We do not distribute cash to i-unit owners
but retain the cash for use in our business. However, the cash equivalent of
distributions of i-units is treated as if it had actually been distributed for
purposes of determining the distributions to our general partner.
Available cash is initially distributed 98% to our limited partners and 2%
to our general partner. These distribution percentages are modified to provide
for incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
- first, 98% to the owners of all classes of units pro rata and 2% to our
general partner until the owners of all classes of units have received a
total of $0.15125 per unit in cash or equivalent i-units for such
quarter;
- second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the owners
of all classes of units have received a total of $0.17875 per unit in
cash or equivalent i-units for such quarter;
- third, 75% of any available cash then remaining to the owners of all
classes of units pro rata and 25% to our general partner until the owners
of all classes of units have received a total of $0.23375 per unit in
cash or equivalent i-units for such quarter; and
- fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units in
cash and to owners of i-units in the equivalent number of i-units, and
50% to our general partner.
Incentive distributions are generally defined as all cash distributions paid
to our general partner that are in excess of 2% of the aggregate value of cash
and i-units being distributed. Our general partner's incentive distribution for
the distribution that we declared for the first quarter of 2005 was $111.1
million. Our general partner's incentive distribution for the distribution that
we declared for the first quarter of 2004 was $90.7 million. Our general
partner's incentive distribution that we paid during the first quarter of 2005
to our general partner (for the fourth quarter of 2004) was $106.0 million. Our
general partner's incentive distribution that we paid during the first quarter
of 2004 to our general partner (for the fourth quarter of 2003) was $85.8
million. All partnership distributions we declare for the fourth quarter of each
year are declared and paid in the first quarter of the following year.
We believe that future operating results will continue to support similar
levels of quarterly cash and i-unit distributions; however, no assurance can be
given that future distributions will continue at such levels.
Certain Contractual Obligations
There has been no material changes in either certain contractual obligations
or our obligations with respect to other entities which are not consolidated in
our financial statements that would affect the disclosures presented as of
December 31, 2004 in our 2004 Form 10-K report.
Information Regarding Forward-Looking Statements
This filing includes forward-looking statements. These forward-looking
statements are identified as any statement that does not relate strictly to
historical or current facts. They use words such as "anticipate," "believe,"
"intend," "plan," "projection," "forecast," "strategy," "position," "continue,"
"estimate," "expect," "may," or the negative of those terms or other variations
of them or comparable terminology. In particular, statements, express or
implied, concerning future actions, conditions or events, future operating
results or the ability to generate sales, income or cash flow or to make
distributions are forward-looking statements. Forward-looking statements are not
guarantees of performance. They involve risks, uncertainties and assumptions.
Future actions, conditions or events and future results of operations may differ
materially from those expressed in these forward-looking statements. Many of the
factors that will determine these results are beyond our ability to control or
predict. Specific factors
62
which could cause actual results to differ from those in the forward-looking
statements include:
- price trends and overall demand for natural gas liquids, refined
petroleum products, oil, carbon dioxide, natural gas, coal and other
bulk materials and chemicals in the United States;
- economic activity, weather, alternative energy sources, conservation
and technological advances that may affect price trends and demand;
- changes in our tariff rates implemented by the Federal Energy
Regulatory Commission or the California Public Utilities Commission;
- our ability to acquire new businesses and assets and integrate those
operations into our existing operations, as well as our ability to
make expansions to our facilities;
- difficulties or delays experienced by railroads, barges, trucks, ships
or pipelines in delivering products to or from our terminals or
pipelines;
- our ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
- shut-downs or cutbacks at major refineries, petrochemical or chemical
plants, ports, utilities, military bases or other businesses that use
our services or provide services or products to us;
- changes in laws or regulations, third-party relations and approvals,
decisions of courts, regulators and governmental bodies that may
adversely affect our business or our ability to compete;
- our ability to offer and sell equity securities and debt securities or
obtain debt financing in sufficient amounts to implement that portion
of our business plan that contemplates growth through acquisitions of
operating businesses and assets and expansions of our facilities;
- our indebtedness could make us vulnerable to general adverse economic
and industry conditions, limit our ability to borrow additional funds
and/or place us at competitive disadvantages compared to our
competitors that have less debt or have other adverse consequences;
- interruptions of electric power supply to our facilities due to
natural disasters, power shortages, strikes, riots, terrorism, war or
other causes;
- our ability to obtain insurance coverage without a significant level
of self-retention of risk;
- acts of nature, sabotage, terrorism or other similar acts causing
damage greater than our insurance coverage limits;
- capital markets conditions;
- the political and economic stability of the oil producing nations of
the world;
- national, international, regional and local economic, competitive and
regulatory conditions and developments;
- the ability to achieve cost savings and revenue growth;
- inflation;
- interest rates;
- the pace of deregulation of retail natural gas and electricity;
- foreign exchange fluctuations;
63
- the timing and extent of changes in commodity prices for oil, natural
gas, electricity and certain agricultural products;
- the extent of our success in discovering, developing and producing oil
and gas reserves, including the risks inherent in exploration and
development drilling, well completion and other development
activities;
- engineering and mechanical or technological difficulties with
operational equipment, in well completions and workovers, and in
drilling new wells;
- the uncertainty inherent in estimating future oil and natural gas
production or reserves;
- the timing and success of business development efforts; and
- unfavorable results of litigation and the fruition of contingencies
referred to in Note 16 to our consolidated financial statements
included elsewhere in this report.
You should not put undue reliance on any forward-looking statements.
See Items 1 and 2 "Business and Properties--Risk Factors" of our Annual
Report on Form 10-K for the year ended December 31, 2004, for a more detailed
description of these and other factors that may affect the forward-looking
statements. When considering forward-looking statements, one should keep in mind
the risk factors described in our 2004 Form 10-K report. The risk factors could
cause our actual results to differ materially from those contained in any
forward-looking statement. We disclaim any obligation to update the above list
or to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
There have been no material changes in market risk exposures that would
affect the quantitative and qualitative disclosures presented as of December 31,
2004, in Item 7A of our 2004 Form 10-K report. For more information on our risk
management activities, see Note 10 to our consolidated financial statements
included elsewhere in this report.
Item 4. Controls and Procedures.
As of March 31, 2005, our management, including our Chief Executive Officer
and Chief Financial Officer, has evaluated the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to Rule 13a-15(b)
under the Securities Exchange Act of 1934. There are inherent limitations to the
effectiveness of any system of disclosure controls and procedures, including the
possibility of human error and the circumvention or overriding of the controls
and procedures. Accordingly, even effective disclosure controls and procedures
can only provide reasonable assurance of achieving their control objectives.
Based upon and as of the date of the evaluation, our Chief Executive Officer and
our Chief Financial Officer concluded that the design and operation of our
disclosure controls and procedures were effective in all material respects to
provide reasonable assurance that information required to be disclosed in the
reports we file and submit under the Exchange Act is recorded, processed,
summarized and reported as and when required, and is accumulated and
communicated to our management, including our Chief Executive Officer and our
Chief Financial Officer, to allow timely decisions regarding required
disclosure. There has been no change in our internal control over financial
reporting during the quarter ended March 31, 2005 that has materially affected,
or is reasonably likely to materially affect, our internal control over
financial reporting.
64
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 3 to our consolidated financial statements
entitled "Litigation and Other Contingencies," which is incorporated herein by
reference.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Item 5. Other Information.
On May 4, 2005, we announced that C. Park Shaper has been elected President
of KMI, KMR and Kinder Morgan G.P., Inc. Mr. Shaper remains a Director of KMR
and Kinder Morgan G.P., Inc. In addition, Mr. Steve Kean has been elected
Executive Vice President, Operations of KMI, KMR and Kinder Morgan G.P., Inc.
and becomes a member of the Office of the Chairman, along with Messrs. Richard
D. Kinder and C. Park Shaper. Ms. Kim Allen, currently Vice President of
Investor Relations and Treasurer, has been elected Chief Financial Officer of
KMI, KMR and Kinder Morgan G.P., Inc. and will continue to manage investor
relations. Mr. David D. Kinder, currently Vice President, Corporate Development,
has been elected Treasurer of KMI, KMR and Kinder Morgan G.P., Inc. and will
continue to manage corporate development. We also announced that (i) Deb
Macdonald, our President - Natural Gas Pipeline would resign from that position
effective October 2005; (ii) Scott Parker, President of KMI's Natural Gas
Pipeline Company of America ("NGPL") would be promoted effective October 2005 to
our President - Natural Gas Pipelines; (iii) David Devine would become President
of NGPL effective October 2005; and (iv) Tom Martin had been promoted to
President - Texas Intrastate Pipelines.
Item 6. Exhibits.
4.1 -- Certificate of Vice President, Treasurer and Chief Financial Officer
and Vice President, General Counsel and Secretary of Kinder Morgan
Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder
Morgan Energy Partners, L.P. establishing the terms of the 5.80%
Senior Notes due March 15, 2035.
4.2 -- Specimen of 5.80% Senior Notes due March 15, 2035 in book-entry form.
4.3 -- Certain instruments with respect to long-term debt of the Partnership
and its consolidated subsidiaries which relate to debt that does not
exceed 10% of the total assets of the Partnership and its consolidated
subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of
Regulation S-K, 17 C.F.R. ss.229.601.
11 -- Statement re: computation of per share earnings.
31.1 -- Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the
Securities Exchange Act of 1934, as adopted pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
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31.2 -- Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the
Securities Exchange Act of 1934, as adopted pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
32.1 -- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 -- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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* Asterisk indicates exhibits incorporated by reference as indicated; all
other exhibits are filed herewith, except as noted otherwise.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
KINDER MORGAN ENERGY PARTNERS, L.P.
(A Delaware limited partnership)
By: KINDER MORGAN G.P., INC.,
its General Partner
By: KINDER MORGAN MANAGEMENT, LLC,
its Delegate
/s/ Kimberly J. Allen
------------------------------
Kimberly J. Allen
Vice President and Chief Financial Officer
(principal financial officer
and principal accounting officer)
Date: May 6, 2005
67